ccs / eor at mexican onshore oil fields - 経済産業省 ... 1. ccs / eor in oil fields 1.1...
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平成27年度地球温暖化対策技術普及等推進事業
(メキシコ、陸上油田における CCSの可能性検討)
(英語版)
CCS / EOR at Mexican Onshore Oil Fields
March, 2016
Mitsui & Co., Ltd.
Mitsubishi Research Institute Inc.
Table of contents
1. CCS / EOR in oil fields ................................................................................................... 1
2. Possible source of CO2 leakage. ..................................................................................... 5
3. CCS/EOR in the context of GHG reduction ..................................................................... 7
4. CCS/EOR methodology under JCM ................................................................................ 9
5. Proposal to the Mexican government............................................................................. 25
1
1. CCS / EOR in oil fields
1.1 Overview
In this study, carbon capture and storage (CCS) projects, including enhanced oil recovery
(EOR) in oil fields is examined from the viewpoint of greenhouse gas reduction. A terrestrial
oil field in Mexico is chosen as the site.
A schematic diagram of EOR is as shown in Figure 1. About half of the injected CO2 is
expected to remain underground.
Figure 1 Schematic diagram of EOR
Major EOR projects around the world are as follows:
2
Table 1 Major EOR projects around the world
Name Type of
reservoir
Year Depth CO2 injection
per year (Mt-
CO2)
Cumulative CO2
injection (Mt-
CO2)
In Salah
(Algeria)
depleted gas
field
2004 1850-1950 1.2 2.5
(at 2008)
Weyburn
(Canada)
oil/gas fields
(CO2-EOR)
2000 1450 3.65 12
(at 2008)
Sleipner
(Norwy)
aquifer 1996 1012 1 11
(at 2009)
Tomakomai
(Japan)
aquifer 2016 1100-1200
2400-2700
(2layers)
0.1 (TBD) 0.3 (TBD)
Val Verde Natural Gas
Plants (USA)
oil/gas fields
(CO2-EOR)
1972 700、945
(2 layers)
1.3
Enid Fertilizer CO2-
EOR Project
(USA)
oil/gas fields
(CO2-EOR)
2003 3000 0.68
Shute Creek Gas
Processing Facility
(USA)
oil/gas fields
(CO2-EOR)
1986 450-3,400
(multiple)
7.0
Century Plant (USA) oil/gas fields
(CO2-EOR)
2010 1NA 8.4
Air Products Steam
Methane Reformer EOR
Project (USA)
oil/gas fields
(CO2-EOR)
2013 1700 1.0
Coffeyville CO2-EOR
project
(USA)
oil/gas fields
(CO2-EOR)
2013 914 1.0
Lost Cabin Gas Plant
(USA)
oil/gas fields
(CO2-EOR)
2013 1,400 0.9
Kemper County Energy
Facility (USA)
oil/gas fields
(CO2-EOR)
2016 NA 3.0
Petra Nova Carbon
Capture Project (USA)
oil/gas fields
(CO2-EOR)
2016 1,640-2,066 1.4
Hydrogen Energy
California Project
(HECA) (USA)
oil/gas fields
(CO2-EOR)
2019 1,650 2.4
Texas Clean Energy
Project (USA)
oil/gas fields
(CO2-EOR)
2019 1NA 1.7
Riley Ridge Gas Plant
(USA)
oil/gas fields
(CO2-EOR)
2020 1NA 2.5
All of the above uses anthropogenically produced CO2 from power plants or chemical plants.
There are also many more EOR projects in the USA which use CO2 gas from gas fields. If this
is included, the total number of EOR projects in the USA reaches 105, of which 61 is located
in the Permian basin encompassing Texas and New Mexico.
3
1.2 Forecasting of CO2 behavior
Forecasting models on CO2 injection and oil recovery can be divided into two categories:
Screening models and Simulation models. Screening models are simple models typically used
to estimate possible increase in oil recovery and maximum amount of CO2 storage, if CCS
activities are continued beyond oil recovery. Such screening models assume a homogeneous
structure of reservoir, whereas in reality this can be highly heterogeneous. Simulation model
addresses such heterogeneity of the reservoir.
Simulation models can further be divided into black oil models which assume homogeneous
composition of oil, and compositional models which predict the movement of oil according to
its components. In CCS/EOR, a compositional model is used since CO2 changes oil
characteristics (viscosity, volume, and miscible pressure), and lighter hydrocarbons are
preferentially extracted by CO2. Example of such simulation model avai lable in the market are:
Eclipse 300 (Schulumberger), CMG-GEM (CMG), and NEXUS (Halliburton).
Typical calculation flow of simulation model is shown below.
4
Figure 2 Schematic diagram of simulation model
INPUT DATA
1. Geologic data: Data needed to make the geologic model
Structure of reservoir (size of oil layer, presence of faults, structural form, size of aquifer)
Log data (contrast, porosity, water saturation)
Core data (porosity, permeability, capillary pressure, relative permeability)
Well data (permeability)
2. PVT data: crude oil production、data used to calculate the behavior of the oil layer in CO2 injection
Crude oil PVT (Bo, μo, Rs, Bg, μg)
CO2-oil phase equilibrium data(MMP, Swelling factor, component analysis)
Creation of the Static Model
Maching the phase behavior between pseudo-components and laboratory data
History Matching
PREDICTION
Amount of CO2 storage, dispersion of
CO2, injection behavior etc
(1) Revision
Yes
No
Creation of the Dynamic Model (1)
Equation of phase behavior,
calculation of flow equiation
OUTPUT
Reservoir pressure,
saturation rate, mole fraction of
pseudo-components
5
2. Possible source of CO2 leakage.
Here, possible sources of CO2 leak are discussed, as well as ways to avoid such leaks.
Leakage from aboveground facilities
Leakage from wells (injection, production, observation, dormant, abandoned)
Leakage from belowground (fracture crossing the oil layer, cap rock, spill point)
These are discussed below.
2.1 Leakage from aboveground facilities
Leakage from aboveground facilities is principally due to corrosion and accidents. Therefore,
it is important to prevent corrosion, as well as monitor the status of corrosion of equipments .
Volume and temperature of the oil and injected CO2 also needs to be monitored.
2.2 Leakage from wells
Leakage from wells can be prevented by appropriately sealing the wells that are not used.
Studies show that appropriately engineered sealing by cement can contain CO2 injected in
reservoirs. Here too, corrosion is an issue due to the presence of CO2 and water. Therefore, it
is important that anticorrosive substances are used. Thickness of cement used for the well
barrier should be at least 100ft, and it is desirable that the total column length reaches 500ft
where possible.
Figure 3 Schematic diagram of well sealing
Liner hanger
6
2.3 Leakage from belowground
Leakage from belowground can be divided into three types: leakage from fracture crossing the
oil layer, leakage through the cap rock, leakage through the spill point.
To minimize the risk of leakage from fracture crossing the oil layer, it is essential that gas
chimneys are not detected through a 3-D seismic analysis. To minimize the risk of leakage
through the cap rock, underground pressure during CO2 injection must be kept below the seal
pressure of cap rock, which can be determined by sample tests . Fracturing pressure (multiplied
by 80%-90% to be on the side of caution) can be a substitute for seal pressure. The initial
pressure, which is below the seal pressure, is a useful and conservative substitute since this is
the pressure at which oil and gas have been kept for a geological timescale.
The thicker the cap rock, the lower the risk of leak. Cap rock thickness alone does not
determine the possibility of leakage, though a cap rock of less than 20m is deemed to require
caution.
Leakage through spill point occurs when CO2 is dissipated to an extent that exceeds the
bottom of oil layer, and into the water layer. To minimize such risk, it is essential to limit CO2
injection to the amount at which CO2 is contained in the oil layer, through a 3-D simulation.
7
3. CCS/EOR in the context of GHG reduction
3.1 CDM
In CDM, two methodologies on CCS / EOR were proposed in 2005 and 2006. They are:
Proposed methodology NM0167 (Recovery of anthropogenic CO2 from large industrial
GHG emission sources and its storage in an oil reservoir) by Mitsubishi Securities.
Proposed methodology NM0168 (The capture of CO2 from natural gas processing plants
and liquefied natural gas (LNG) plants and its storage in underground aquifers or
abandoned oil/gas reservoirs) by Mitsubishi Research Institute.
NM0167 concerned an EOR project in Vietnam, whereas NM0168 concerned a non-EOR CCS
in Malaysia, where CO2 from a LNG processing facility was to be stored underground. In
NM0167, treatment of emission from oil produced was stipulated as follows:
People will continue to rely on fossil fuels at a similar rate and consumption will remain unchanged,
regardless of (small changes in) the supply of a single type. Therefore, if this additional crude oil was
not available (because tertiary production was not carried out) the supply would be made up b y
increasing extraction of other fossil fuels such as coal and natural gas. Considering the amount of world
coal reserves and the recent spike in natural gas prices, it is likely that coal would be a more price
competitive option than natural gas, for many large fossil fuel consumers.
Consideration of these methodologies by the CDM Executive board and the methodologies
panel was never conducted, since eligibility of CCS projects was a matter of negotiation in the
COP/MOP. In 2011, the regulation “Modalities and procedures for carbon dioxide capture and
storage in geological formations as clean development mechanism project activities ” was
adopted in COP/MOP7 (Durban). In this regulation, extensive requirements were stipulated for
the host country, project participant and the project itself. One of the notable clauses is the one
on monitoring, which states that the monitoring of the geological storage site “shall not be
terminated earlier than 20 years after the end of the last crediting period of the CDM p roject
activity or after the issuance of CERs has ceased, whichever occurs first” .
Such clauses provide safety against permanence issues which accompany any CCS/EOR
project, but these place a heavy burden on the side of the project participants. Possibly as a
result, no proposals on CCS methodologies have been submitted to date.
3.2 ACR
In 2015, a methodology on EOR was adopted under the American Carbon Registry (ACR), a
nonprofit scheme organized by Winrock International and is recognized under the Californian
emissions trading program. The methodology “Methodology for Greenhouse Gas Emission
8
Reductions From Carbon Capture and Storage Projects” is applicable to projects which
sequester CO2 in oil and gas fields in the USA and Canada. Treatment of CO2 emissions from
produced oil follows that of NM0167. It is possible that the methodology envisages injection
of CO2 from power plants, since the baseline includes a “standards-based” approach.
9
4. CCS/EOR methodology under JCM
4.1 Background and rationale
A methodology is developed under the JCM scheme, to minimize the monitoring burden on the
side of the project developers. If the “Modalities and procedures for carbon dioxide capture
and storage in geological formations as clean development mechanism project activities (2011)”
is followed, modelling exercises may exceed what is normally required of oil field operation.
Instead of monitoring seepage and mandatory monitoring periods, this sets out conditions in
which seepage is highly unlikely to occur.
To this end, a series of eligibility criteria are conceived, as follows:
Table 2: Eligibility criteria and their rationale
# Criterion Rationale
1 The project captures, transports and stores
anthropogenic CO2 generated as a
byproduct into on-shore oil wells,
including enhanced oil recovery projects.
Onshore oil reservoirs have had adequate geological surveys
conducted.
2 Selected storage site does not include
international waters.
Emissions from international waters under current rules do
not count for national emissions.
3 Selected storage site is not a source for
potable water supply.
Security concerns.
4 Gas chimneys are not detected in the
storage site according to a 3-D seismic
analysis conducted prior to implementation
of the project.
There is no risk of seepage through cap rock. Offers more
convincing evidence of robustness than other indicators such
as cap rock thickness. Indicators such as depth offers
suitability for storage but not security against leakage.
5 Plan for CO2 injection is designed in a way
that initial reservoir pressure is not
exceeded at any time.
Reservoir pressure is the pressure that has kept gas and oil
through geological timescale, and it has been demonstrated
that cap rock can withstand this pressure
6 Contractual and financial arrangements are
in place to guarantee that the injection and
production wells will be sealed
appropriately upon closure (2 cement
barriers, each 100ft).
Only source of non-geological leakage is through abandoned
wells, which will be sealed adequately.
7 Maximum allowable CO2
injection in the
storage site is calculated using a screening
model which fulfills the conditions
specified in the methodology.
A 3-D compositional model is used to calculate the maximum
allowable injection, so as not to leak CO2 through spill points
or cap rock.
8 Activities related to the project including
oil extraction and confirmed reserves are
reported to the competent authority on an
annual basis.
Procedures to correct forecasting of the properties of oil
fields are in place in case of discrepancies.
4.2 The methodology text
Based on the above, the methodology text is determined to be as follows . The template format
for Mexico is used.
10
JCM Proposed Methodology Form
Cover sheet of the Proposed Methodology Form
Form for submitting the proposed methodology
Host Country United Mexican States
Name of the methodology proponents
submitting this form
Mitsui & Co. Ltd.
Mitsubishi Research Institute Inc.
Sectoral scope(s) to which the Proposed
Methodology applies
8. Mining/Mineral production;
Title of the proposed methodology, and
version number
CO2 capture and storage in on-shore oil wells
Ver.1.0
List of documents to be attached to this
form (please check):
The attached draft JCM-PDD:
Additional information
Date of completion
History of the proposed methodology
Version Date Contents revised
11
A. Title of the methodology
CO2 capture and storage in on-shore oil wells
B. Terms and definitions
Terms Definitions
CO2 capture and
storage (CCS)
Capture and transport of carbon dioxide from anthropogenic
sources of emissions, and the injection of the captured carbon
dioxide into an underground geological storage site for long-term
isolation from the atmosphere.
Enhanced oil
recovery (EOR)
The process of producing hydrocarbons from subsurface
reservoirs using thermal, gas, or chemical injection techniques.
Storage site The total site where the CO2 will be stored, including reservoir,
cap rock and overburden.
Cap rock Low permeability formation above the CO2 storage formation
through which no CO2 migration should occur
Seepage Transfer of carbon dioxide from beneath the ground surface or
seabed ultimately to the atmosphere or ocean
C. Summary of the methodology
Items Summary
GHG emission reduction
measures
GHG emission reduction is achieved by injecting CO2
generated as a byproduct into oil reservoirs.
Calculation of reference
emissions
Reference emissions are calculated on the basis of
monitored amount of injected CO2.
Calculation of project
emissions
Project emissions are calculated on the basis of energy
consumption for CO2 capture, transport and injection,
flaring associated with oil/gas production, and oil and gas
recovery process due to containment failure from above
ground installations. CO2 emission from seepage is assumed
not to occur so long as the injected CO2 is below the
maximum limit of injection calculated pursuant to the
methodology.
12
Monitoring parameters Monitoring parameters are as follows:
CO2 injected into oil wells
CO2 imported from source
CO2 generated at source
CO2 recovered from production wells
Electricity and fuel consumption required to recover,
transport and inject CO2.
D. Eligibility criteria
This methodology is applicable to projects that satisfy all of the following criteria.
Criterion 1 The project captures, transports and stores anthropogenic CO 2 generated
as a byproduct into on-shore oil wells, including enhanced oil recovery
projects.
Criterion 2 Selected storage site does not include international waters.
Criterion 3 Selected storage site is not a source for potable water supply.
Criterion 4 Gas chimneys are not detected in the storage site according to a 3 -D
seismic analysis conducted prior to implementation of the project.
Criterion 5 Plan for CO2 injection is designed in a way that initial reservoir pressure
is not exceeded at all times. Execution of this is checked at the time of
verification, in order to confirm that initial reservoir pressure is not
exceeded at all times up to the point of verification.
Criterion 6 Contractual and financial arrangements are in place to guarantee that the
injection and production wells encompassing the storage site will be
sealed appropriately, by installing first and second barriers made of
cement, both more than 100ft (30.5metres) thick.
Criterion 7 Maximum allowable CO2 injection in the storage site is calculated using a
simulation model which fulfills the conditions specified in the
methodology. Procedure to appropriately update the model is in place, and
such procedure is overseen by a qualified engineer.
Criterion 8 Activities related to the project including oil extraction and confirmed
reserves are reported to the competent authority on an annual basis.
13
E. Emission Sources and GHG types
Reference emissions
Emission sources GHG types
Gas injected into the storage site CO2
Project emissions
Emission sources GHG types
Fossil fuel consumption for CO2 capture, transport and injection to
the storage site.
CO2
Electricity consumption for CO2 capture, transport and injection to
the storage site.
CO2
Flaring associated with oil/gas production CO2, CH4
Emissions from oil and gas recovery process due to containment
failure from above ground installations
CO2
Emissions from venting of CO2 at the injection wells or other
facilities
CO2
14
F. Establishment and calculation of reference emissions
F.1. Establishment of reference emissions
Reference emission is defined as CO2 supplied to the injection facility. In this way, CO2
containment failure during CO2 capture from emission source and transportation do not
need to be considered.
In the case that CCS is mandated by law or regulation, the reference scenario will be
the compliance of such mandate, and CO2 injection above the mandate will be considered
as the reference emission.
The emissions associated with the combustion of hydrocarbons produced by EOR
products (i.e., produced oil or gas), which occurs outside the project boundary at the
point of use, are excluded. This approach is consistent with other GHG emission
reduction methodologies, where emissions related to the use of the products are not
included. Moreover, oil production through EOR would most likely displace an
equivalent quantity of imported oil or in some cases domestic primary (i.e., non-EOR)
production.
This methodology ensures net emission reduction, since a ceiling in creditable emission
reduction is established at a value well below maximum allowable CO 2 injection.
F.2. Calculation of reference emissions
F2.1 Calculation of maximum allowable CO2 injection in the storage site CO2inj,max.
Maximum allowable CO2 injection in the storage site CO2inj,max.is decided by following
two factors.
i) Reservoir pressure
CO2inj,max. will be evaluated when the reservoir pressure reaches the threshold pressure.
If the threshold pressure is unknown, then initial reservoir pressure will be used due to
the safety of CO2 injection.
ii) Spill point
CO2inj,max. will be evaluated when the injected CO2 arrives at spill point of the
reservoir
15
CO2inj,max, is calculated using a simulation model, according to the following provisions.
(1) Requirements of the simulation model
Such simulation model is a three-dimension compositional simulation model which can
perform the following functions.
1. Prediction of the phase equilibrium between CO2 and reservoir fluids
2. Calculation of dynamic flow behavior in the reservoir for a long period of time (longer
than 1,000 years)
Examples of such simulation model are as follows:
Eclipse 300 reservoir simulator (by Schlumberger).
CMG-GEM (by CMG)
NEXUS (by Haliburton)
(2) Requirements of data
The model incorporates the following data.
Type of data Details of data Method of collection
Geological data Reservoir structure
Area of the reservoir
Aquifer size below the reservoir
Existence of fault
Seismic interpretation and
Log interpretation data
Reservoir data Initial reservoir pressure and
temperature
Well test data
Reservoir thickness
Rock properties
Log interpretation and well
test data
Relative permeability and
capillary pressure
Core analysis
Fluid pressure, volume,
temperature (PVT) data
PVT test of oil and gas
Oil swelling factor PVT test between CO2 and
oil
Compositional data and oil
recovery data
Core flood test by CO2
injection
Phase dynamics
between CO2 and
reservoir fluid
Minimum miscibility pressure Slim tube test
Well data Well completion interval Well data
Pattern of CO2-EOR/CCS Well pattern diagram
Field data Production data of gas/oil/water
Reservoir pressure profile
Production data
F2.2 Calculation of reference emissions
Reference emissions are calculated on the basis of CO 2 injected during a given time
period.
16
𝑅𝐸𝑝 = 𝐹𝐿𝑖𝑛𝑗,𝑝 × 𝐶𝑖𝑛𝑗,𝐶𝑂2,𝑝 × 𝐷𝐶𝑂2 − 𝐶𝑂2𝑟𝑒𝑔,𝑝 (1)
Where
REp = Reference emissions during a given time period p. [tCO2/p]
FLinj,p = Amount of gas injected by the project during a given time period p.
[Nm3/p]
Cinj,CO2 = CO2 concentration in injected gas during a given time period p.
[dimensionless]
DCO2 = Density of CO2 at standard condition (=0.001976ton/m3)
CO2reg,p = Amount of CO2 required to be injected according to regulation during
a given time period p. [tCO2/p]
G. Calculation of project emissions
Project emissions are summation of various emissions of CO 2 as a result of project, as
shown below.
G.1 Overall equation
𝑃𝐸𝑝 = 𝑃𝐸𝑓𝑢𝑒𝑙,𝑝 + 𝑃𝐸𝑒𝑙𝑒𝑐,𝑝 + 𝑃𝐸𝑓𝑙𝑎𝑟𝑒,𝑝 + 𝑃𝐸𝑟𝑒𝑐𝑜𝑣,𝑝 + 𝑃𝐸𝑣𝑒𝑛𝑡,𝑝 (2)
Where
PEp = Project emissions during a given time period p. [tCO2/p]
PEfuel,p = Project CO2 emissions due to fossil fuel consumption for CO2
capture, transport and injection during a given time period p.
[tCO2/p]
PEelec,p = Project CO2 emissions due to electricity consumption for CO2
capture, transport and injection during a given time period p.
[tCO2/p]
PEflare,p = Project CO2 and CH4 emissions due to flaring associated with oil/gas
production during a given time period p. [tCO2/p]
PErecov,p = Project CO2 emissions from oil and gas recovery process due to
containment failure from above ground installations during a given
time period p. [tCO2/p]
PEvent,p = Project CO2 emissions from venting of CO2 at the injection wells or
other facilities during a given time period p. [tCO2/p]
G.2 Specific components of the equation
(1) Calculation of PEfuel,p
PEfuel,p (Project CO2 emissions due to fossil fuel consumption for CO2 capture, transport
and injection during a given time period p) is calculated on the basis of fossil fuel
17
consumed by the project.
𝑃𝐸𝑓𝑢𝑒𝑙,𝑝 = ∑ (𝐹𝐶𝑖,𝑝 × 𝑁𝐶𝑉𝑖 × 𝐸𝐹𝑖)𝑖 (3)
Where
PEfuel,p = Project CO2 emissions due to fossil fuel consumption for CO2
capture, transport and injection during a given time period p.
[tCO2/p]
FCi,p = Consumption of fossil fuel i for the purpose of CO2 capture, transport
and injection during the period p. [mass or volume unit]
NCVi = Net calorific value of fossil fuel type i.[ GJ/mass or volume unit]
EFi = CO2 emission factor of fossil fuel i [tCO2/GJ]
i = Type of fuel
(2) Calculation of PEelec,p
PEelecl,p (Project CO2 emissions due to electricity consumption for CO2 capture, transport
and injection during a given time period p) is calculated on the basis of electricity
consumed by the project. Refer to section I for CO2 emission factor of grid electricity.
𝑃𝐸𝑒𝑙𝑒𝑐,𝑝 = 𝐸𝐶𝑝 × 𝐸𝐹𝑒𝑙𝑒𝑐,𝑝 (4)
Where
PEelec,p = Project CO2 emissions due to electricity consumption for CO2
capture, transport and injection during a given time period p.
[tCO2/p]
ECp = Total consumption of electricity for the purpose of CO2 capture,
transport and injection during the period p. [MWh]
EFelec,p = CO2 emission factor of electricity during the period p [tCO2/MWh]
j = Equipment which consumes electricity
(3) Calculation of PEflare,p
PEflare,p (Project CO2 and CH4 emissions due to flaring associated with oil/gas production
during a given time period p) is calculated on the basis of CO2 emissions from combusted
flare, and CH4 emissions from uncombusted flare.
𝑃𝐸𝑓𝑙𝑎𝑟𝑒,𝑝 = {𝐹𝐿𝑓𝑙𝑎𝑟𝑒,𝑝
0.0224× 𝐶𝑓𝑙𝑎𝑟𝑒,𝐶,𝑝 × 44 × 𝐸𝐹𝐹𝑓𝑙𝑎𝑟𝑒,𝑝 +
𝐹𝐿𝑓𝑙𝑎𝑟𝑒,𝑝
0.0224× 𝐶𝑓𝑙𝑎𝑟𝑒,𝐶𝐻4 × 16 × (1 −
𝐸𝐹𝐹𝑓𝑙𝑎𝑟𝑒,𝑝) × 𝐺𝑊𝑃𝐶𝐻4} × 10−6 (5)
Where
PEflare,p = Project CO2 emissions due to flaring associated with oil/gas
production during a given time period p. [tCO2/p]
FLflare,p = Amount of gas flared during a given time period p. [Nm3/p]
Cflare,C,p = Non-methane hydrocarbon concentration in flared gas during a given
time period p. [dimensionless]
18
EFFflare,p = Flare efficiency during a given time period p. [dimensionless]
Cflare,CH4,p = Methane concentration in flared gas during a given time period p.
[dimensionless]
GWPCH4 = GWP of methane (=23)
0.0224 = Constant [m3/mol]
44 = Molecular weight of CO2 [g/mol]
16 = Molecular weight of CH4 [g/mol]
(4) Calculation of PErecov,p
PErecov,p (Project CO2 emissions from oil and gas recovery process due to containment
failure from above ground installations during a given time period p) is calculated on the
basis of the difference between the amount of gas supplied to CO2 separation system and
the amount of gas reinjected, under the assumption that the balance is emitted to the
atmosphere. If this results in a negative value, then PErecov,p is assumed to be zero.
𝑃𝐸𝑟𝑒𝑐𝑜𝑣,𝑝 = {max ((𝐹𝐿𝑠𝑒𝑝,𝑝 × 𝐶𝑠𝑒𝑝,𝐶𝑂2,,𝑝 − 𝐹𝐿𝑟𝑒𝑖𝑛𝑗,𝑝 × 𝐶𝑟𝑒𝑖𝑛𝑗,𝐶𝑂2,𝑝) × 𝐷𝐶𝑂2) , 0} (6)
Where
PErecov,p = Project CO2 emissions from oil and gas recovery process due to
containment failure from above ground installations during a given
time period p. [tCO2/p]
FLsep,p = Amount of gas supplied to CO2 separation system during a given time
period p. [Nm3/p]
Csep,CO2.p = Average CO2 concentration in gas supplied to CO2 separation system
during a given time period p. [dimensionless]
FLreinj,p = Amount of gas reinjected during a given time period p. [Nm3/p]
Creinj,CO2p.p = Average CO2 concentration in gas reinjected during a given time
period p. [dimensionless]
DCO2 = Density of CO2 at standard condition (=0.001976ton/m3)
(5) Calculation of PEventl,p
PEvent,p (Project CO2 emissions from venting of CO2 at the injection wells or other
facilities during a given time period p) is calculated on the basis of the number of venting
incidents of the equipment concerned, and the volume of such equipment.
𝑃𝐸𝑣𝑒𝑛𝑡,𝑝 = 𝑉𝑣𝑒𝑛𝑡,𝑖,𝑝 × 𝐷𝐶𝑂2 (7)
Where
PEvent,p = Project CO2 emissions from venting of CO2 at the injection wells or
other facilities during a given time period p. [tCO2/p]
Vvent,i,p = Total Volume of equipment i that are vented during a given time
period p. [Nm3]
DCO2 = Density of CO2 at standard condition (=0.001976ton/m3)
19
H. Calculation of emissions reductions
H.1 Basic formula
Emission reductions are calculated as follows:
𝐸𝑅𝑝 = 𝑅𝐸𝑝 − 𝑃𝐸𝑝 (8)
Where
ERp = Emission reductions during a given time period p. [tCO2/p]
REp = Reference emissions during a given time period p. [tCO2/p]
PEp = Project emissions during a given time period p. [tCO2/p]
H.2 Conditionality
In this methodology, it is deemed that seepage from injected CO2 does not occur. To this
end, maximum allowable CO2 injection in the storage site (CO2inj,max) is derived using
a simulation model as shown in section F2.1.
If initial reservoir pressure is exceeded at any time or monitoring point during the CO 2
injection, then it is assumed that all CO2 injected to the ground is emitted to the air
through possible cap rock fracture, and the net result would be cumulative project
emissions from fuel and electricity consumption, as follows:
∑ 𝐸𝑅𝑝 = − ∑ 𝑃𝐸𝑓𝑢𝑒𝑙,𝑝 + 𝑃𝐸𝑒𝑙𝑒𝑐,𝑝𝑝𝑝 (9)
I. Data and parameters fixed ex ante
The source of each data and parameter fixed ex ante is listed as below.
Parameter Description of data Source
CO2inj,max Maximum allowable CO2 injection in the
storage site
Calculated as per section
F2.1
CO2reg,p Amount of CO2 required to be injected
according to regulation during a given
time period p. [tCO2/p]
Available regulation
pertaining required CO2
injection.
NCVi Net calorific value of fossil fuel type i.
[ GJ/mass or volume unit]
In the order of preference,
a) values provided by the
fuel supplier;
b) measurement by the
20
project participants;
c) regional or national
default values;
d) IPCC default values
provided in table 1.2 of
Ch.1 Vol.2 of 2006 IPCC
Guidelines on National
GHG Inventories.
Lower value is applied.
EFi CO2 emission factor of fossil fuel i
[tCO2/GJ]
In the order of preference,
a) values provided by the
fuel supplier;
b) measurement by the
project participants;
c) regional or national
default values;
d) IPCC default values
provided in table 1.4 of
Ch.1 Vol.2 of 2006 IPCC
Guidelines on National
GHG Inventories.
Lower value is applied.
EFelec,p CO2 emission factor of electricity during
the period p [tCO2/MWh]
For captive electricity: 0.8* [tCO2/MWh]
*The most recent value available from
CDM approved small scale methodology
AMS-I.A at the time of validation is
applied.
Apply the latest value
determined by the secretary
of energy (SENER)
4.3 Spreadsheet
The accompanying spreadsheet are as follows:
21
4.3.1 Input sheet
JCM_MX_F_PMS_ver01.0
JCM Proposed Methodology Spreadsheet Form (Input Sheet) [Attachment to Proposed Methodology Form]
Table 1: Parameters to be monitored ex post
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)
Monitoring
point No.Parameters Description of data
Estimated
ValuesUnits
Monitoring
optionSource of data Measurement methods and procedures
Monitoring
frequency
Other
comments
1 FLinj.p
Amount of gas injected by
the project during a given
time period p .Nm
3 COn-site
measurements.Mesurement is conducted by orifice flow meters Continuous
2 Cinj,CO2,p
CO2 concentration in
injected gas during a given
time period p.
DimensionlessCOn-site
measurements.Gas chromatography
At least once
in every
month
3 FCcoal,p
Consumption of coal for the
purpose of CO2 capture,
transport and injection
during the period p
mass or
volume
unit.
COn-site
measurements.
Use either mass or volume meters. In cases where fuel is supplied from small
daily tanks, rulers can be used to determine mass or volume of the fuel
consumed, with the following conditions: The rule gauge is part of the daily
tank and calibrated at least once a year and have a book of control for
recording the measurements (on a daily basis or per shift);
• Accessories such as transducers, sonar and piezoelectronic devices are
accepted if they are properly calibrated with the ruler gauge and receiving a
reasonable maintenance;
• In case of daily tanks with pre-heaters for heavy oil, the calibration will be
made with the system at typical operational conditions.
Periodically, as
specified
according to
national or in-
house rules
4 FCHFO,p
Consumption of residual oil
for the purpose of CO2
capture, transport and
injection during the period p
mass or
volume
unit.
COn-site
measurements.
Use either mass or volume meters. In cases where fuel is supplied from small
daily tanks, rulers can be used to determine mass or volume of the fuel
consumed, with the following conditions: The rule gauge is part of the daily
tank and calibrated at least once a year and have a book of control for
recording the measurements (on a daily basis or per shift);
• Accessories such as transducers, sonar and piezoelectronic devices are
accepted if they are properly calibrated with the ruler gauge and receiving a
reasonable maintenance;
• In case of daily tanks with pre-heaters for heavy oil, the calibration will be
made with the system at typical operational conditions.
Periodically, as
specified
according to
national or in-
house rules
5 FCdiesel,p
Consumption of diesel for
the purpose of CO2
capture, transport and
injection during the period p
mass or
volume
unit.
COn-site
measurements.
Use either mass or volume meters. In cases where fuel is supplied from small
daily tanks, rulers can be used to determine mass or volume of the fuel
consumed, with the following conditions: The rule gauge is part of the daily
tank and calibrated at least once a year and have a book of control for
recording the measurements (on a daily basis or per shift);
• Accessories such as transducers, sonar and piezoelectronic devices are
accepted if they are properly calibrated with the ruler gauge and receiving a
reasonable maintenance;
• In case of daily tanks with pre-heaters for heavy oil, the calibration will be
made with the system at typical operational conditions.
Periodically, as
specified
according to
national or in-
house rules
6 FCgas,p
Consumption of natural gas
for the purpose of CO2
capture, transport and
injection during the period p
mass or
volume
unit.
COn-site
measurements.
Use either mass or volume meters. In cases where fuel is supplied from small
daily tanks, rulers can be used to determine mass or volume of the fuel
consumed, with the following conditions: The rule gauge is part of the daily
tank and calibrated at least once a year and have a book of control for
recording the measurements (on a daily basis or per shift);
• Accessories such as transducers, sonar and piezoelectronic devices are
accepted if they are properly calibrated with the ruler gauge and receiving a
reasonable maintenance;
• In case of daily tanks with pre-heaters for heavy oil, the calibration will be
made with the system at typical operational conditions.
Periodically, as
specified
according to
national or in-
house rules
7 FCi,p
Consumption of other fuel i
for the purpose of CO2
capture, transport and
injection during the period p
mass or
volume
unit.
COn-site
measurements.
Use either mass or volume meters. In cases where fuel is supplied from small
daily tanks, rulers can be used to determine mass or volume of the fuel
consumed, with the following conditions: The rule gauge is part of the daily
tank and calibrated at least once a year and have a book of control for
recording the measurements (on a daily basis or per shift);
• Accessories such as transducers, sonar and piezoelectronic devices are
accepted if they are properly calibrated with the ruler gauge and receiving a
reasonable maintenance;
• In case of daily tanks with pre-heaters for heavy oil, the calibration will be
made with the system at typical operational conditions.
Periodically, as
specified
according to
national or in-
house rules
8 ECp
Total Consumption of
electricity in equipment j for
the purpose of CO2
capture, transport and
injection during the period p
MWh COn-site
measurements.Electricity meters
At least once in
every month
9 FLflare.p
Amount of gas flared during
a given time period pNm
3 COn-site
measurements.Mesurement is conducted by orifice flow meters Continuous
10 Cflare,C,p
Non-methane hydrocarbon
concentration in flared gas
during a given time period p
DimensionlessCOn-site
measurements.Gas chromatography
At least once
in every
month
11 Cflare,CH4,p
Methane concentration in
flared gas during a given
time period p.
DimensionlessCOn-site
measurements.Gas chromatography
At least once
in every
month
12 EFFflare,p
Flare efficiency during a
given time period p
13 FLsep.p
Amount of gas supplied to
CO2 separation system
during a given time period p.
Nm3 C
On-site
measurements.Mesurement is conducted by orifice flow meters Continuous
14 Csep,CO2,p
Average CO2
concentration in gas
supplied to CO2 separation
system during a given time
DimensionlessCOn-site
measurements.Gas chromatography
At least once
in every
month
15 FLreinj.p
Amount of gas reinjected
during a given time period pNm
3 COn-site
measurements.Mesurement is conducted by orifice flow meters Continuous
16 Creinj,CO2,p
Average CO2
concentration in gas
reinjected during a given
time period p.
DimensionlessCOn-site
measurements.Gas chromatography
At least once
in every
month
17 Vvent,I,p
Total volume of equipments
that are vented during a
given time period p
Nm3 C
On-site
measurements.
Derived by multipling the incidence of venting by the
volume of equipment that are vented.
22
Table 2: Project-specific parameters to be fixed ex ante
(a) (c) (d)
ParametersEstimated
ValuesUnits
CO2inj,max tCO2
CICO2p-1 tCO2
CO2reg,p tCO2
NCVcoal
GJ / mass
or volume
unit
NCVHFO
GJ / mass
or volume
unit
NCVdiesel
GJ / mass
or volume
unit
NCVgas
GJ / mass
or volume
unit
NCVi
GJ / mass
or volume
unit
EFcoal tCO2/GJ
EFHFO tCO2/GJ
EFdiesel tCO2/GJ
EFgas tCO2/GJ
EFi tCO2/GJ
EFelec,p tCO2/MWh
PEfuel,p-1 tCO2
PEelec,p-1 tCO2
Table3: Ex-ante estimation of CO2 emission reductions
Units
tCO2/p
[Monitoring option]
Option A
Option B
Option C
(f)
Other comments
(e)
Source of data
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.4 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.4 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.4 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.4 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
Apply the latest value determined by the secretary of energy (SENER)
Based on the actual measurement using measuring equipments (Data used: measured values)
(b)
Description of data
CO2 emission reductions
#REF!
Based on public data which is measured by entities other than the project participants (Data used: publicly recognized data such as statistical data and specifications)
Amount of CO2 required to be injected
according to regulation during a given time
period p
Calculated from relevant legislation of the country or region
Net calorific value of natural gas
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.2 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
Net calorific value of diesel
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.2 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
Net calorific value of residual oil
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.2 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
CO2 emission factor of any other fuel used
CO2 emission factor of electricity during
the period p
Net calorific value of any other fuel used
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.2 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
Based on the amount of transaction which is measured directly using measuring equipments (Data used: commercial evidence such as invoices)
Net calorific value of coal
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.2 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
CO2 emission factor of coal
In the order of preference, a) values provided by the fuel supplier, b) measurement by the
project participants, c) regional or national default values, d) Lower value of IPCC default
values provided in the table 1.4 of Ch.1 Vol.2 of 2006 IPCC Giudelines on National GHG
Inventories.
Cumulative project CO2 emissions due to
fossil fuel consumption for CO2 capture,
transport and injection during up to the
period p-1.
Calculated according to the methodology
Cumulative project CO2 emissions due to
electricity consumption for CO2 capture,
transport and injection during up to the
period p-1.
Calculated according to the methodology
CO2 emission factor of natural gas
CO2 emission factor of diesel
CO2 emission factor of residual oil
CO2 concentration in injected gas during a
given time period pCalculated according to the simulation model specified in the methodology
Cumulative CO2 injection as a result of the
project up to the period p-1Calculated according to the methodology
23
4.3.2 Calculation process sheet
JCM_MX_F_PMS_ver01.0
1. Calculations for emission reductions Fuel type Value Units Parameter
Emission reductions during the period p #REF! tCO2/p ERp
2. Selected default values, etc.
Net calorific value of coal 25.8 GJ/t NCVcoal
Net calorific value of residual oil 39.8 GJ/t NCVHFO
Net calorific value of diesel oil 41.4 GJ/t NCVdiesel
Net calorific value of natural gas 46.5 GJ/t NCVgas
Net calorific value of any other fuel 39.8 GJ/t NCVi
Emission factor of coal 0.09461 t-CO2/GJ EFcoal
Emission factor of residual oil #REF! t-CO2/GJ EFHFO
Emission factor of diesel oil 0.0726 t-CO2/GJ EFdiesel
Emission factor of natural gas 0.0726 t-CO2/GJ EFgas
Emission factor of any other fuel 0.0543 t-CO2/GJ EFi
Density of CO2 at standard condition (ton/m3) 0.001976 ton/Nm3 DCO2
Amount of CO2 required to be injected according to regulation during a given time period p 0 t-CO2 CO2reg,p
CO2 emission factor of electricity during the period p 0 t-CO2/MWh EFelec
GWP of CH4 23 Dimensionless
Cumulative CO2 injection as a result of the project up to the period p 0 CICO2,p
CO2inj,max 0 CO2inj,max
3. Calculations for reference emissions
Reference emissions during the period p 0.00 tCO2/p REp
4. Calculations of the project emissions
Project emissions during the period p #REF! tCO2/p PEp
Project CO2 emissions due to fossil fuel consumption for CO2 capture, transport and injection during a given time period p #REF! tCO2/p PEfuel,p
Project CO2 emissions due to electricity consumption for CO2 capture, transport and injection during a given time period p 0 tCO2/p PEelec,p
Project CO2 and CH4 emissions due to flaring associated with oil/gas production during a given time period p 0.00 tCO2/p PEflare,p
Project CO2 emissions from oil and gas recovery process due to containment failure from above ground installations during a given time period p 0 tCO2/p PErecov,p
Project CO2 emissions from venting of CO2 at the injection wells or other facilities during a given time period p 0 tCO2/p PEvent,p
JCM Proposed Methodology Spreadsheet Form (Calculation Process Sheet)
[Attachment to Proposed Methodology Form]
24
4.3.3 Other
An extra spreadsheet is required to check whether the cumulative injection is within the
maximum allowable injection calculated as per the methodology.
[List of Default Values]
Density of CO2 at standard condition 0.001976 ton/Nm3
Default net calorific value of coal 25.8 GJ/t
Default net calorific value of residual oil 39.8 GJ/t
Default net calorific value of diesel oil 41.4 GJ/t
Default net calorific value of natural gas 46.5 GJ/t
Default net calorific value of any other fuel 39.8 GJ/t
Default emission factor of coal 0.09461 t-CO2/GJ
Default emission factor of residual oil 0.0726 t-CO2/GJ
Default emission factor of diesel oil 0.0726 t-CO2/GJ
Default emission factor of natural gas 0.0543 t-CO2/GJ
Default emission factor of any other fuel 0.0755 t-CO2/GJ
GWP of CH4 23 Dimensionless
Additional parameters
Cumulative CO2 injection as a result of the project up to the period p 0.00 tCO2/p CICO2,p
Cumulative CO2 injection as a result of the project up to the period p-1 0 tCO2/p CICO2,p-1
Amount of gas injected by the project during a given time period p 0 Nm3 FLinj,p
CO2 concentration in injected gas during a given time period p. 0.00 DimensionlessCinj,CO2,p
CO2 concentration in injected gas during a given time period p 0.001976 ton/Nm3 DCO2,p
Project CO2 emissions from oil and gas recovery process due to containment failure from above ground installations during a given time period p0 tCO2/p PErecov,p
25
5. Proposal to the Mexican government
5.1 Ways to facilitate CCS/EOR
Two approaches to facilitate CCS/EOR can be conceived.
Mapping of major emission sources and possible reservoirs.
Support on monitoring, to complement private sector initiatives on CCS/EOR.
In March, 2014, Energy ministry (SENER) has formulated the “CCUS Technology Roadmap”,
which stipulates, inter alia, that regulatory framework adjustments will be completed by 2016,
and by 2020 there will be legally binding observation for permanent monitoring, as well as
additional institutional financing and funding mechanisms. It is hoped that such regulatory
framework and schemes are realized. Mexico is already undertaking regulatory reform on
CCS/EOR, in cooperation with the World Bank.
Incentives on CCS/EOR implemented throughout the world is tabulated as follows.
Table 3 Incentives on CCS/EOR implemented throughout the world
Country Policy Type Description
USA CO2 Emission Reduction
Standard (“Federal Clean
Power Plan”)
New federal carbon pollution standards for power
plants encourage CCS technology as a mechanism of
meeting required emission reductions
USA R&D Program (“DOE
Industrial CCS RD&D
Program”)
Extensive R&D program which supports large-scale
demonstration projects
USA Tax Credits (Ҥ48A Power
Sector Tax Credit”,
Ҥ48B Industrial
Gasification Tax Credit”,
“§45Q Tax Credit”)
Investment tax credit for coal power plants using CCS,
tax credits for industrial gasification with CCS projects,
direct credits for capture and storage of CO2
USA Price Stabilization (“Coal
with Carbon Capture
Sequestration Act”)
Proposed legislation which provides price stabilization
of carbon dioxide captured and sold from coal power
plants
Canada Emissions Performance
Standard
Emission reduction policies in Alberta include CCS as
an eligible activity. National CO2 standards for coal
power plants include provision for extension of
operating permits for units which implement CCS.
Norway Carbon Tax Carbon tax introduced in 1991 has prompted use of CCS
– notably at the Sleipner CCS project in the North Sea
United
Kingdom
Emissions Performance
Standard
A CO2 standard was set specifically to ensure that new
coal power plants are built with CCS
United
Kingdom
Capital Grants (“UK CCS
Commercialization
Competition”)
The UK CCS Commercialization Competition provides
capital funding to support installation of commercial -
scale CCS.
United
Kingdom
Contract-for-difference
Feed-in-tariffs (“CfD
Regime”)
A financial provision which provides stable revenue
streams to power providers using CCS
European
Union
Capital Grants (“NER 300”,
“European Energy Program
for Recovery”)
The EU-ETS introduced a specific mechanism to
incentivize CCS, known as “NER 300”. This
mechanism offers EU emission allowances to support
development of CCS. The EU also supports
demonstration CCS projects with financial support
26
through the European Energy Program for Recovery.
(Source: IEA)