CCS / EOR at Mexican Onshore Oil Fields - 経済産業省 ... 1． CCS / EOR in oil fields 1.1 Overview In this study, carbon capture and storage (CCS) projects, including enhanced

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


[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


[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


[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


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]


(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]


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


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.











Periodically, as

specified

according to

national or in-

house rules

5 FCdiesel,p

Consumption of diesel for

the purpose of CO2



mass or

volume

unit.

COn-site

measurements.











Periodically, as

specified

according to

national or in-

house rules

6 FCgas,p

Consumption of natural gas




mass or

volume

unit.

COn-site

measurements.











Periodically, as

specified

according to

national or in-

house rules

7 FCi,p

Consumption of other fuel i




mass or

volume

unit.

COn-site

measurements.











Periodically, as

specified

according to

national or in-

house rules

8 ECp

Total Consumption of

electricity in equipment j for

the purpose of CO2



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


10 Cflare,C,p

Non-methane hydrocarbon

concentration in flared gas

during a given time period p



At least once

in every

month

11 Cflare,CH4,p

Methane concentration in

flared gas during a given

time period p.



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


14 Csep,CO2,p

Average CO2

concentration in gas

supplied to CO2 separation

system during a given time



At least once

in every

month

15 FLreinj.p

Amount of gas reinjected

during a given time period pNm

3 COn-site


16 Creinj,CO2,p

Average CO2

concentration in gas

reinjected during a given

time period p.



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.




Inventories.




Inventories.




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




Inventories.

Net calorific value of diesel




Inventories.

Net calorific value of residual oil




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




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




Inventories.

CO2 emission factor of coal




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 (“§48A Power

Sector Tax Credit”,

“§48B 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)

Documents

CCS / EOR at Mexican Onshore Oil Fields - 経済産業省 ... 1． CCS / EOR in oil fields 1.1 Overview In this study, carbon capture and storage (CCS) projects, including enhanced