平成２８年度二国間クレジット取得等インフラ整備

調査事業（ＪＣＭ実現可能性調査） 

メキシコ、陸上油田におけるＣＣＳプロジェクトへの

ＪＣＭ適用に向けた技術的検討 

調査報告書（英語版）

Feasibility Study Project for the JCM (2016FY) Technical Study for Application of JCM to CCS at Onshore Oil Field in Mexico

March, 2017

Toyo Engineering Corporation

ii

Content

1． Introduction ..................................................................................................................... 1

Background................................................................................................................ 1 1.1

2． CCS Monitoring ............................................................................................................... 2

Mexican Guidelines of Hydrocarbon Metrological Procedure .................................... 2 2.1

2.1.1 Management of Measurement (Article 7 of LFMN) ..................................................... 2 2.1.2 Measurement Information to be Reported (Article 10 of LFMN) ................................. 3 2.1.3 Measurement Systems at the Measurement Point (Article 19 of LFMN) ................... 4 2.1.4 Measurement of Flow Rates (Articles 21 through 25 of LFMN) ................................. 4 2.1.5 Determination of Hydrocarbon Quality (Articles 26 through 29) ................................. 4

Monitoring Methods and their Frequency in CCS Projects in Other Countries .......... 5 2.2

2.2.1 Monitoring Guidelines in EU ....................................................................................... 5 2.2.2 Monitoring Guidelines in USA ..................................................................................... 7

Monitoring Items Required for JCM Mechanism ........................................................ 8 2.3

2.3.1 Monitoring Methods to Detect CO2 Leakage from Surface Production Facility ......... 9 2.3.2 Monitoring Methods to Detect CO2 Leakage from Wells ............................................ 9 2.3.3 Monitoring Methods to Detect CO2 Leakage from Underground Reservoir ............. 10 2.3.4 Monitoring after Cessation of CO2 Injection ............................................................. 10

Comparison of Monitoring Requirements in JCM and Regulations in Other Countries2.4 10

Monitoring Options ................................................................................................... 11 2.5

2.5.1 Applicable Monitoring Options .................................................................................. 11 2.5.2 Monitoring System Developed in Japan ................................................................... 13

3． Well Abandonment Plan and Regulations .................................................................. 15

Regulations of Well Abandonment in Some Countries ............................................ 15 3.1

3.1.1 United Kingdom......................................................................................................... 16 3.1.2 Regulation of Well Abandonment in Norway (NORSOK Standards) ........................ 23 3.1.3 Standards of Well Abandonment in USA .................................................................. 31 3.1.4 Well Integrity of CO2-EOR, SACROC (Texas, USA) ................................................ 34

Conclusion ............................................................................................................... 35 3.2

4． Study of CO2 Corrosion Protection ............................................................................ 36

General Concept of Corrosion Protection in Oil Industries ...................................... 36 4.1

4.1.1 Evaluation of Corrosion Rate by Corrosion Prediction Models ................................. 36 4.1.2 Corrosion Protection of Wells ................................................................................... 37 4.1.3 Flowline and Gathering Line ..................................................................................... 38 4.1.4 Production Facilities .................................................................................................. 38 4.1.5 CO2 Injection Facilities ............................................................................................. 39 4.1.6 Transportation Pipelines of Produced Gas and Liquid ............................................. 39

Conclusion ............................................................................................................... 39 4.2

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5． CCUS-Technology-Roadmap and Mexico’s Climate Change Policy ........................ 41

CCUS Technology Roadmap ................................................................................... 41 5.1

5.1.1 General Overview ..................................................................................................... 41 5.1.2 CO2 Capture ............................................................................................................. 41 5.1.3 CO2 Utilization and Storage ..................................................................................... 42 5.1.4 Public Policy .............................................................................................................. 43

Mexico’s Climate Change Policy .............................................................................. 46 5.2

5.2.1 Mexico’s GHG Emissions and Reduction Target ...................................................... 46 5.2.2 GHG Emissions Reduction Policies .......................................................................... 48

Observations ............................................................................................................ 50 5.3

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Figure

Figure 3-1 Position of Well Barrier ............................................................................................. 17 Figure 3-2 Position of Well Barrier ............................................................................................. 17 Figure 3-3 Length of Well Barrier .............................................................................................. 18 Figure 3-4 Example of Well Abandonment ................................................................................. 19 Figure 3-5 Image of Horizontal Well Abandonment ................................................................... 22 Figure 3-6 Well Barrier ............................................................................................................... 24 Figure 3-7 Example of Multiple Reservoir Zones ...................................................................... 25 Figure 3-8 Well Abandonment of Open Hole ............................................................................. 26 Figure 3-9 Well Abandonment of Perforated Well ...................................................................... 27 Figure 3-10 Well Abandonment of Multiple Zones with Slotted Liner or Sand Screen ............. 28 Figure 3-11 Well Abandonment of Slotted Liners in Multiple Reservoirs .................................. 29 Figure 3-12 Recommended Well Abandonment for Class VI ..................................................... 32 Figure 3-13 Cement and Casing Taken from Well 49-6 .............................................................. 35 Figure 5-1 CCUS Technology Roadmap in Mexico (CO2 capture from Power Plants) ............. 42 Figure 5-2 CCUS Technology Roadmap in Mexico (CO2-EOR) ............................................... 42 Figure 5-3 CCUS Technology Roadmap in Mexico (Public Policy) .......................................... 45 Figure 5-4 Mexico’s GHG Emissions by Economic Sector and Gas .......................................... 46 Figure 5-5 Mexico’s GHG Emissions Trends ............................................................................. 47 Figure 5-6 Mexico’s 2030 GHG Mitigation Target ..................................................................... 47 Figure 5-7 Mexico’s GHG Mitigation Scenarios ........................................................................ 48

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Tables

Table 2-1 Quality of Liquid Hydrocarbon Including Condensate in Tanks and Pipelines ............ 5 Table 2-2 Quality of Gas Hydrocarbons in Tanks and Pipelines ................................................... 5 Table 2-3 CCS Monitoring Procedures ......................................................................................... 6 Table 2-4 Example of Monitoring Items and Frequency .............................................................. 7 Table 2-5 Monitoring Items Investigated in the study “CCS / EOR at Mexican Onshore Oil

Fields” (FY 2015) ................................................................................................................. 9 Table 2-6 Comparison of Monitoring Requirements .................................................................. 11 Table 2-7 Monitoring Tools and Methods in CO2-EOR and CCS Projects ................................ 12 Table 3-1 Regulations of Well Abandonment ............................................................................. 15 Table 3-2 Guideline for the Verification of Cement Barrier ....................................................... 21 Table 3-3 Functions and Purposes of Well Barrier ...................................................................... 23 Table 3-4 Referred Table-22 in Figure 5-8 to Figure 5-11 .......................................................... 30 Table 3-5 Referred Table-24 in Figure 5-8 to Figure 5-11 .......................................................... 31 Table 3-6 Classification of Cement in API ................................................................................. 33 Table 3-7 Cement Samples of SACROC .................................................................................... 34 Table 4-1 Corrosion Prediction Model ........................................................................................ 37 Table 4-2 Material Selection for Wells ....................................................................................... 38 Table 5-1 List of Key Issues for the Development of Regulatory Framework for CCUS .......... 44 Table 5-2 Carbon Tax (by types of fossil fuel) ............................................................................ 49

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Units and Abbreviat ions

In this report, following units and abbreviations are used. Units

Units Meaning Remarks

acre Acre (area) 1acre = 4,046.9m2

bbl Barrel

1bbl = 159l

Mbbl = 1,000bbl

MMbbl = 1,000,000bbl

bbl/STB Volume factor of oil, Bo

cp Viscosity, μ 1cp = 1mPa・s

degAPI API degree (Specific Gravity)

degC Temperature (Celsius) degC = 5/9*(degF-32)

degF Temperature (Fahrenheit) degF = 9/5*degC + 32

ft Feet (Length) 1ft = 0.3048m

inch

” Inch (Length)

1inch = 25.4mm

13 3/8” = 13 and 3/8 inch

KTA Annual Kilo Ton

MJ Mega joule 1MJ = 1,000,000 J

lb Pound 1lb = 0.454 kg

md Millidarcy (Permeability) 1md = 9.87×10-16m2

Mol% Molar Fraction

MPA Mils per Annual (Corrosion Rate) 1MPA = 0.025 mm/yr

Pa Pascal 1Pa = 0.000145psi

Peso Peso Mexicano

ppf Pound per feet 1.488 kg/m

ppm Parts per million 1ppm = 0.0001%

psi Pound per square inch (Pressure) 6,895Pa = 0.068 Atm (Approx.)

psia Pound per square inch

(Absolute Pressure)

psia = psig + atmospheric pressure at the

location

psig Pound per square inch

(Gauge Pressure)

scf Standard cubic foot

1scf = 0.0283m3

Mscf = 1,000 scf

MMscf = 1,000,000 scf

STB Stock tank barrel Volume of Oil at Standard Conditions

(60degF & 14.7psi)

t-CO2 Ton (Mass of CO2)

t-CO2e CO2 Equivalent Ton Mass of Greenhouse Gas converted to

CO2

USD US dollar

vii

/d Per day 1bbl/d = Barrel per day

/yr Per year 1bbl/yr = Barrel per year Abbreviations

Abbreviations Formal Name / Meaning

API American Petroleum Institution

API-MPMS API Manual of Petroleum Measurement Standards

APS-PNG Accelerator Porosity Sonde - Pulsed Neutron Generator

ASEA Agencia de Seguridad, Energía y Ambiente

ASTM American Society for Testing and Materials

Bo Volume factor of oil

CAPEX Capital Expenditure

CBL Cement Bond Logging

CCS Carbon Capture and Storage

CCUS Carbon Capture, Utilization and Storage

CDM Clean Development Mechanism

CEEMS Chugai Environmental Effect Monitoring System

CEL Certificados de Energía Limpia

CER Certified Emission Reductions

CET Cement Evaluation Tool

CFE Comision Federal de Electricidad

CIBP Cast Iron Bridge Plug

CNH Comision Nacional de Hidrocarburos

CO2-EOR CO2 Enhanced Oil Recovery

CPET Corrosion Protection Evaluation Tool

CPGLV Complejo Procesador de Gas La Venta

CPQ Cang Complejo Petroquímico Cangrejera

CPQ Cos Complejo Petroquímico Cosoleacaque

CRA Corrosion Resistant Alloy

CSG Casing

DOE Department of Energy

ECS Elemental Capture Spectroscopy

EOR Enhanced Oil Recovery

EPA Environmental Protection Agency

ESP Electrical Submersible Pump

ETS Emission Trading System

FBG Fiber Bragg Grating

GHG Greenhouse Gas

viii

GOR Gas Oil Ratio

IEPS Impuesto Especial sobre Producción y Servicios

InSAR Interferometric Synthetic Aperture Radar

IOR Improved Oil Recovery

IRR Internal Rate of Return

ISO International Organization for Standardization

JCM Joint Crediting Mechanism

LACT Lease Automated Custody Transfer

LFMN Ley Federal sobre Metrología y Normalización

Federal Law of Metrology and Standardization

MDEA Methyl Diethanolamine

MRV Monitoring, Reporting and Verification

NPV Net Present Value

OPEX Operating Expenditure

PEMEX Petroleos Mexicanos

PEP Pemex Pexploration and Production (PEMEX’s subsidiary company)

PDD Project Design Document

PPQ Pemex Petroquímica、PEMEX Petrochemical

PRM Permanent Reservoir Monitoring

RENE Registro Nacional de Emisiones

RESTEC Remote Sensing Technology Center of Japan

RITE The Research Institute of Innovative Technology for the Earth

RST Reservoir Saturation Tool

TBG Tubing

TDT Thermal Decay Time Log

TEG Tri-Ethylene Glycol

TOC Top of Cement

UKOOA UK Offshore Operations Association

USDW Underground Source of Drinking Water

USI Ultra-Sonic Imager

VCS Verified Carbon Standard

VDL Variable Density Log

VSP Vertical Seismic Profiling

.

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1． Introduction

Background 1.1

Crude oil production in Mexico has declined from 3.55 million bbl/d in 2005 to 2.3 million bbl/d in 2016, which is mainly caused by the rapid decline of crude oil production in Cantarell oil field (from 2 million bbl/d in 2000 to 0.34 million bbl/d in 2016) and other several oil fields. Thus, CNH (Comision Nacional de Hidrocarburos) emphasizes the importance of IOR/EOR in Mexican existing (brown) oil fields in the report of “The future of Oil Production in Mexico. Advanced and Enhanced Recovery IOR-EOR”. At the same time, PEMEX published the report “ EOR as a Driver for CCS Projects in Mexico, 2012”, where CO2-EOR and CCS project will contribute to the increase of crude oil production with CO2 utilization as well as the CO2 reduction as the global warming mitigation.

Secretariat of Energy (Sener), Secretariat of the Environment and Natural Resources (Semarnat), PEMEX and Federal Electricity Commission (CFE) prepared “CCUS Technology Roadmap in Mexico” in March 2014 as a long term plan for CCUS (Carbon Capture, Utilization and Storage) including CO2-EOR, and Mexican government is proactive in the realization of CCUS accordingly. Also, INDC (Intended Nationally Determined Contributions) submitted to United Nations by Mexico in 2015 is defining CO2 storage as a promising measure of greenhouse gas reduction to achieve the reduction target in 2030.

The candidates of existing oil fields for CO2 storage are located in Tampico, Poza Rica and Magallanes-Sanches. PEMEX is planning to conduct a CO2-EOR/CCS pilot test and succeeding commercial operation in the oil fields in accordance with CCUS Roadmap, and an onshore oil field is selected as a first oil field for CO2-EOR/CCS execution.

In Japan, Mitsubishi Research Institute, Inc and Mitsui & Co., Ltd. performed the study “CCS / EOR at Mexican Onshore Oil Fields” as a Global Warming Mitigation Technology Promotion Project in 2016 (Financial Year 2015), in order to realize JCM (Joint Crediting Mechanism). In the study, the technical evaluation of CO2-EOR planned by PEMEX was undertaken, and also CCS methodology under JCM was developed. In line with the study results, further detail technical study and planning for JCM application were conducted in this study.

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2． CCS Monitoring

CO2 leak in CCS projects may lead to significant impact on environment, human health and storage volume and therefore monitoring and mitigation procedure for CO2 leak will be required. Recommended monitoring plan was investigated after survey of monitoring standards in Mexico and other countries, and research of monitoring requirements in JCM mechanism.

Mexican Guidelines of Hydrocarbon Metrological Procedure 2.1

Metrological procedure for produced/injected hydrocarbon, water and CO2 in CCS projects in Mexico must at first follow technical guideline of LFMN (Ley Federal sobre Metrología y Normalización: Federal Law of Metrology and Standardization). This technical guideline defines metrological procedure, system design, installation and maintenance.

LFMN will be revised around by 2019 for implementation of CCS project in Mexico after consent of CNH (Comisión Nacional de Hidrocarburos), ASEA (Agencia de Seguridad, Energía y Ambiente), and Ministry of Energy according to the information from SEMARNAT and PEMEX.

2.1.1 Management of Measurement (Article 7 of LFMN)

Operators of hydrocarbon producing field(s) must follow the following standards and procedures:

(1) Standards and Regulations

Operators must comply with the regulations and standards in Annex II of LFMN guideline. Annex II refers to the following standards of Mexico, API MPMS (API Manual of Petroleum Measurement Standards), ISO, etc.

(1) Design and installation of measuring system (2) Standard for static measurement of hydrocarbon volume in tank (3) Standard for dynamic measurement of hydrocarbon liquid (4) Standard for dynamic measurement of hydrocarbon gas (5) Standard for property measurement of hydrocarbon liquid and gas (6) Standard for delivery and reception of produced hydrocarbon (7) Standard for volumetric measurement at supply point (8) Standard for management of measurement (9) Standard for installation, safety and durability of measuring system/instruments

(2) Measurement System

Operator must establish and maintain measurement system in accordance with LFMN guideline. For this purpose, operator must consider at least the following elements:

Selection of Measurement System 1）

The measurement system must be suitable for the intended use under the characteristics of fluid and operating conditions

3

Selection of Measuring Instruments 2）

The measurement instruments must be duly selected and located in accordance with the regulations and standards in accordance with Annex II of LFMN guideline.

Calibration 3）

The measurement instruments and system must be calibrated on the basis of the manufacturer's specifications, process and regulations and the frequency of calibration must comply with Annex II of LFMN guideline. Operator must calibrate at least once a year unless calibration frequency is specified in the guideline.

Maintenance 4）

Measurement instruments must be maintained in accordance with the corresponding specification and procedure of the instruments.

Verification 5）

Operator must verify that the metering system is working properly corresponding to verification plan.

(3) Responsibilities and Competencies of the Staff

The personnel of operator involved in the measurement operation must have the necessary skills and must be trained by competent national, foreign agencies, or educational institutions.

2.1.2 Measurement Information to be Reported (Article 10 of LFMN)

Operator must report information on hydrocarbon measurement to CNH in accordance with the following requirements:

Information to be reported daily; Operator must report information of the volume (flow rate),

pressure, temperature, density and quality (composition) of hydrocarbons. Information to be reported monthly; Operator must report monthly to CNH within the first 5

business days in the next month the following information: The production rate and quality of extracted or produced oil, condensate, natural gas and

water The hydrocarbon volume extracted from each reservoir and field, if requested by CNH The balance of hydrocarbons from wells and reservoir to each measurement point; The volume of natural gas used or flared, and The volume of natural gas that has been vented in exceptional cases

Information to be reported annually; Operator must report to CNH the following information within the first 30 business days in the next year: General information identified in the contract Name of responsible officers Average daily and monthly production volume of oil, natural gas and water in the year

4

Predicted production volume of the next year List of measurement systems and their instruments, including measurement points Any accidents, failure of measurement instruments and substantial change of

hydrocarbons characteristics Daily production rate of hydrocarbons at wells, fields, and measuring points Standards and procedures of measurement and utilized measurement systems Responsibility and competence of operator’s staff and training system for them

2.1.3 Measurement Systems at the Measurement Point (Article 19 of LFMN)

With respect to the measurement point, operator must comply with the following requirements:

Location: The measurement point may be located inside or outside the Contractual Area or

the Area of Allocation, as determined by CNH in their relevant technical report, in accordance with the provisions of LFMN guideline.

Capacity: Operator must ensure that the measurement system is continuously available, so that the maximum flow rate of hydrocarbons can be measured even when a set of parallel measuring instruments is out of operation.

Telemetry systems: Operator must use telemetric systems to monitor hydrocarbon measurement at measuring point in real time. At all times, operator must guarantee access to such systems at no cost to CNH.

Quality: Operator must ensure that the quality of the hydrocarbons can be determined in the measurement point in accordance with the article 28 of LFMN guideline.

LACT Unit (Lease Automated Custody Transfer Unit): The LACT unit must be installed at measurement point with the safety operational and physical functions that do not allow alterations, as well as having the capacity to safeguard the information with alarms to any changes and faults in calculated values. At all times, operator must ensure that CNH has access to such a LACT unit that collects the information, at no cost to CNH.

2.1.4 Measurement of Flow Rates (Articles 21 through 25 of LFMN)

Measurement of hydrocarbons may be carried out in volume or in mass but must be reported to CNH in the terms and conditions indicated in LFMN guideline. Measurement instruments for temperature, pressure and density must comply with the regulations and standards in Annex II of LFMN guideline. Produced water can be measured in volume or in mass, but must be reported in volume. Operator must measure and report to CNH the volume of hydrocarbon gas produced, injected, flared and vented. Operator can use multiphase flowmeter in accordance with their development plan after approval of CNH.

2.1.5 Determination of Hydrocarbon Quality (Articles 26 through 29)

(1) Liquid Hydrocarbon

Liquid hydrocarbon produced from wells or separators: Density, viscosity, salinity and contents of sulfur, water and metal must be reported.

Measurement point: The quality of the liquid hydrocarbon at the measurement point must

5

comply with the market or commercial conditions. CNH guideline must determine the quality characteristics to be met at the point of measurement as follows

Table 2-1 Quality of Liquid Hydrocarbon Including Condensate in Tanks and Pipelines

Item Standard

Water and solid content Less than 2% by volume

Hydrogen sulfide (H2S) Less than 1ppm (mol)

Salt content Less than 200mg/L

Sulfur content Less than 5% (mass)

Vapor pressure in tank Less than 80kPa

Source) Technical guideline of CNH

(2) Natural Gas

For each stream of natural gas from wells or separators, the density, humidity and composition including impurities must be reported. The quality of the hydrocarbon gas at the measurement point must comply with the market or commercial conditions.

CNH guideline must determine the quality characteristics to be met at the point of measurement as follows:

Table 2-2 Quality of Gas Hydrocarbons in Tanks and Pipelines

Item Standard

Humidity (H2O) Less than 100mg/m3 (6.5lb/MMscf)

Total sulfur Less than 150mg/m3

Sulfide acid (H2S) Less than 6mg/m3

calorific value 37.30-43.60 MJ/m3

Carbon dioxide (CO2) Less than 3 vol. %

Oxygen (O2) Less than 0.2 vol. %

Source) Technical guideline of CNH

Monitoring Methods and their Frequency in CCS Projects in Other Countries 2.2

In order to detect CO2 behavior in the reservoir, CO2 leak from wells and sealing rock, environmental impact, monitoring procedures for CCS project are proposed in the other countries. CCS guidelines in EU and USA were checked.

2.2.1 Monitoring Guidelines in EU

(1) Monitoring Items

European Commission proposes the following monitoring procedures. Operator is not required to monitor all items and required monitoring items are determined and approved by the authorized agency in accordance with reservoir characters, volume of injected CO2, injection pressure, formation pressure, etc.

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Table 2-3 CCS Monitoring Procedures

Source) Implementation of Directive 2009/31/EC on the Geological Storage of Carbon Dioxide, Guidance

Document 2, European Commission, 2011

Monitoring Procedure for CCS Operation 1）

The same parameters such as CO2 production/injection volume, well head pressure, reservoir pressure, etc. as required to be monitored in CO2-EOR will be also required to be monitored in CCS project.

Monitoring Distribution of Injected CO2 2）

For the purpose of monitoring CO2 distribution in reservoir, wireline logging to estimate change in reservoir saturation, offset or walkaway VSP and cross-well tomography for estimation of CO2 front and 4D seismic survey will be carried out.

Monitoring CO2 Leakage from Wells and Sealing Rock 3）

In order to detect leak of injected CO2, annulus pressure will be monitored in wells. Micro-seismic survey may be carried out to identify leak through faults and sealing cap rock.

Monitoring to Assess Environmental Impact 4）

Change in ground surface elevation or tilting, CO2 concentration, vegetative stress, etc. will be monitored.

(2) Monitoring Frequency

Monitoring frequency is not stipulated in regulations and will be approved by the authorized agency at the time of submission of CCS project plan. Monitoring results will be reported in the frequency (at least once a year) stipulated by the European Committee. An example monitoring plan is shown

7

below:

Table 2-4 Example of Monitoring Items and Frequency

Source) Implementation of Directive 2009/31/EC on the Geological Storage of Carbon Dioxide, Guidance Document

2, European Commission, 2011

(3) Monitoring After Cessation of CO2 Injection

Monitoring will be required also after cessation of CO2 injection. There is no specific provision of monitoring items and frequency though they will be planned and approved by the authorized agency.

2.2.2 Monitoring Guidelines in USA

Environment Protection Agency (EPA) of USA ensures safe drinking water with Safe Drinking Water Act including Underground Injection Control (UIC) Class VI Program. The regulation stipulates requirements for site selection, construction materials, monitoring procedures, financial qualification of operator, etc.

(1) At the Time of Permit Application

Operator will be required to submit monitoring plan.

Mandatory Required Contingency

Pre-inj Inj Post-inj Long term

Injectionrate

Flow meter × Cont Well head

WellPressure

Pressuredevice

× Baselinedata

Cont Cont Every year Well head

ReservoirPressure

Pressuredevice

× Baselinedata

Cont Cont Every year Down hole

Temperature

Thermometer ×

Baselinedata Cont Cont Every year

Well head& Down

holeInjectedgascomposition

Gassamples

× Cont Well head

Repeated3D seismic ×

Baselinesurvey

Order ofyears,

based onmodeling

Possiblesurveyafter

severalyears

Possiblesurveryafter

severalyears

Fault area

Aqueouschemistry

× Roughlyyearly

Observation well

Annuluspressure

× Order offer months

Well bore

Wirelinelogging

× Order offer months

Well bore

Opticalwelllogging

×Order of

fer months Well bore

Cementbondlogging

×Order of

fer months Well bore

Microseismicmonitoring

Geophonesbehindcasing ofwells

× Baselinedata

Cont (Cont) Injectionwell

Wellintegrity

Category of monitoring Project phase and FrequencyLocation

Parameterto be

monitored

Techniqueadopted

Faultintegrity

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(2) Monitoring Items Required during CO2 Injection

The following monitoring items will be required:

CO2 injection pressure, rate and volume; the pressure in the annulus between tubing and

casing; and the annulus fluid volume added (continuously except during well workover operation)

Corrosion monitoring of the well materials on a quarterly basis Periodic monitoring of the ground water quality and geochemical changes above the

confining zone(s) A demonstration of external mechanical integrity of well at least once per year until the

injector will be plugged and, if required, a casing inspection log at a frequency established in the testing and monitoring plan

A pressure fall-off test at least once every five years Testing and monitoring to track the extent of the carbon dioxide plume and the presence or

absence of elevated pressure The Director (UIC program Director) may require surface air monitoring and/or soil gas

monitoring to detect movement of carbon dioxide. The monitoring frequency and spatial distribution of surface air monitoring and/or soil gas monitoring must be decided using baseline data.

(3) Monitoring after Cessation of CO2 Injection

Following the cessation of injection, the owner or operator will continue to conduct monitoring for at least 50 years in UIC Program. If the owner or operator can demonstrate before 50-year timeframe based on monitoring and other site-specific data, that the geologic sequestration project no longer poses an endangerment to Underground Sources of Drinking Water (USDWs), the owner or operator can be approved to site closure before 50 years. Monitoring period was shortened to 10 years in a CCS project in Illinoi. US Department of Energy, DOE recommends to monitor reservoir pressure at least 5 years after cessation of CO2 injection.

Monitoring Items Required for JCM Mechanism 2.3

Monitoring items required for JCM were investigated through the study “CCS / EOR at Mexican Onshore Oil Fields” (FY 2015). Monitoring items are classified into two categories. One is to calculate sequestrated CO2 volume and the other is to detect CO2 leak. The latter item was discussed in this section.

9

Table 2-5 Monitoring Items Investigated in the study “CCS / EOR at Mexican Onshore Oil Fields” (FY 2015)

Monitoring item Frequency Monitoring tool

Surface

Facility

Pressure, temperature and

flow rate Daily

Pressure/temperature gauges and

flowmeter

Fluid composition Periodically Chromatograph

Corrosion monitoring Periodically Chemical tests

Ground

surface CO2 content As required CO2 sensor

Wells

Injected gas volume and

CO2 content Daily Flowmeter and chromatograph

Tubing and annulus

pressures

daily Pressure gauge

CO2 content in produced

gas

Periodically Gas compositional analysis

Integrity of producers and

injectors

Once before

commencement of

injection and when

required

CBL-VDL or USI logging

(cement bond log and ultra-sonic

Imager log)

Reservoir Distribution of injected

CO2 (CO2 plume) When required

Well logging, VSP, Cross-well

tomography and 4D seismic

survey

2.3.1 Monitoring Methods to Detect CO2 Leakage from Surface Production Facility

In addition to monitoring items in conventional oil production operation (production rate, injection rate, fluid composition, pressure, and temperature of production/injection facility, etc.), corrosion rate will be measured from corrosion monitoring with test coupon or iron count if required.

The above monitoring items are required during CO2 injection. Surface production facilities will be demolished after cessation of CO2 injection and there is no possibility of CO2 leak, therefore no monitoring will be required for surface facility.

Atmospheric CO2 content at ground surface will be measured if required.

2.3.2 Monitoring Methods to Detect CO2 Leakage from Wells

Integrity of cement bond around casing will be confirmed with cement bond log (CBL-VDL) or ultrasonic imager tool (USI) before commencement of CO2 injection. Cement squeeze will be carried out if cement bond is not enough.

Well head pressure/temperature and tubing/casing pressure will be monitored periodically while CO2 is injected. Production/injection rate of oil, hydrocarbon gas, water and CO2 will be monitored in producers and injectors.

Reservoir pressure does not increase after cessation of CO2 injection and CO2 leak through caprock

10

or cement around casing of wells will not occur (Jewell et al., 2012 and Zhang et al., 2011). Injected CO2 will be stably sequestrated in underground reservoir if appropriate well abandonment has been implemented (NETL, 2010). Therefore, no monitoring will be required after cessation of CO2 injection.

2.3.3 Monitoring Methods to Detect CO2 Leakage from Underground Reservoir

The following items will be monitored during CO2 injection to understand reservoir pressure and underground CO2 distribution. Reservoir simulation will be studied to predict reservoir pressure and underground CO2 distribution.

(1) Monitoring Reservoir Pressure

Bottomhole pressure in producers, injectors and observation wells will be measured. Actual reservoir performance will be evaluated from the difference in pressure predicted from reservoir simulation model.

(2) Monitoring CO2 Content in Produced Fluid

CO2 content of produced fluid in producers will be measured. Actual CO2 distribution will be estimated and compared with the prediction from reservoir simulation model.

(3) Monitoring Underground Distribution of Injected CO2

Reservoir is composed of layers and permeability of each layer is different. Therefore, volume of injected CO2 is different in each layer owing to its permeability. Saturation of CO2 in reservoir around the wells will be evaluated from neutron log (Reservoir Saturation Tool) or VSP if required.

(4) Seismic Survey to Monitor Underground Distribution of Injected CO2

4D seismic survey (repeated 3D seismic surveys) may be undertaken to understand underground distribution of injected CO2 in large oil field that can afford high survey cost. Land 3D seismic survey costs about 200,000 USD/km2.

2.3.4 Monitoring after Cessation of CO2 Injection

The study “CCS / EOR at Mexican Onshore Oil Fields” (FY 2015) concluded that monitoring is not required after cessation of CO2 injection as discussed in 4. 4. 1.

Comparison of Monitoring Requirements in JCM and Regulations in Other Countries 2.4

Monitoring requirements in JCM and regulations in other countries are listed in the following table.

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Table 2-6 Comparison of Monitoring Requirements

Monitoring Options 2.5

2.5.1 Applicable Monitoring Options

Monitoring items required in CO2-EOR and CCS projects and applicable monitoring tools and methods are shown in the following table.

Monitoring Tool EU USA JCMWell Integrity CBL-VDL, USI △ ○ △

Tubing, Annulus and CasingPressure

Pressure Gauge △ ○ ○

Oil Gravity Hydrometer × × ○

CO2 Content of ProducedGas

CO2 Sensor, Chromatograph × × ○

Corrosion of Bottom HoleAssembly

Iron Count, Test Coupon △ ○ ○

Bottom Hole Pressure andTemperature

Pressure and TemperatureGauges △ × ○

Water Saturation in ReservoirAround Well

Reservoir Saturation Tool (e.g.Pulsed Neutron Log) △ × ×

Gathering Line andStation

Corrosion Iron Count, Test Coupon × × ○

CO2 Injection FacilityInjection pressure,temperature, volume, andCO2 content

Pressure and TemperatureGauges, Flowmeter and CO2Sensor/Chromatograph

△ ○ ○

SeparatorPressure, Temperature, GOR,Water Cut and CO2 Content

Pressure and TemperatureGauges, Flowmeter and CO2Sensor/Chromatograph

× × ○

Other FacilitiesPressure, Temperature andFlow Rate

Pressure and TemperatureGauges and Flowmeter × × ○

Elevation Change Tiltmeter, InSar △ × ×

Atmopheric CO2 Content CO2 Sensor △ ○ △

Vegetative StressHyperspectral, Multi-spectralImaging △ × ×

VSPCross-Well Tomography4D Seismic SurveyPRM (Permanent ReservoirMonitoring)

Leakage through Fault andCaprock

Microseismic Survey △ × ×

Ground Water Zoneabove Reservoir andVadose Zone

Chemical Change of GroundWater

Geochemical MonitoringGround Water Sample × ○ ×

EU: Guideline of European Committee ○: RequiredUSA: Underground Injection Controle Class VI program △: Required if necessaryJCM: Required Monitoring Items by the draft of MRV methodology in FY2016's JCM study ×: Not required

△ △ △

Monitoring Item

Wells

Surface Production Facility

Ground Surface

Subsurface

ReservoirDistribution of Injected CO2

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Table 2-7 Monitoring Tools and Methods in CO2-EOR and CCS Projects

No. Required monitoring items Monitoring options (tools/methods)

1 Corrosion monitoring

Detection of leak from pressure/temperature change

Iron count and corrosion coupon

Electrochemical and resistance measurement

2 Cement integrity of well

Logging (CBL, CET, USI, CPET, etc.)

Fiber optic sensors to detect temperature, pressure and

strain

3 Change of oil saturation in reservoir Well logging (RST, APS, ECS, etc.)

4 Injected CO2 distribution in reservoir

Prediction of CO2 migration from reservoir simulation

model

Cross-well tomography

4D seismic survey

Permanent reservoir modeling (PRM)

Micro-seismic

5 CO2 concentration in ground surface to detect CO2 leak

CO2 sensors

6 Ground strain (deformation) InSAR, tiltmeter

(1) Corrosion Monitoring

For the purpose of corrosion protection for facilities in oil and gas fields and pipelines, appropriate material selection, injection of neutralizer or corrosion inhibitor, electric anticorrosion method (cathodic protection and anodic protection) will be implemented. Periodic corrosion monitoring methods have been established such as test piece, corrosion coupon, electrochemical and resistance measurement. Wireline logging of CPET (Corrosion Protection Evaluation Tool) will be utilized as a periodic corrosion monitoring method for casing and tubing of wells. Online real time corrosion monitoring system is in development stage recently using highly sensitive corrosion sensors and probes and processing of these data.

(2) Integrity of Cement in Well

Evaluation of cement integrity of well will be carried out with periodic corrosion logging. In addition to it, fiber optic sensors will be installed in cement of wells to continuously monitor pressure, temperature and strain. Corrosion logging includes CBL (Cement Bond Logging), CET (Cement Evaluation Tool), USI (Ultra-Sonic Imager), etc. Fiber optic sensor includes DTS (Distributed Temperature Sensing), DAS (Distributed Acoustic Sensing), FBG (Fiber Bragg Grating), etc. which monitor deformation of casing and cement with measuring temperature, pressure and strain.

(3) Change of Oil Saturation in Reservoir with CO2 Injection

Change of oil saturation in reservoir during CO2 injection is predicted with reservoir simulation model. Actual oil saturation in reservoir around wells can be measured by wireline logging.

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Saturation logging tools such as RST (Reservoir Saturation Tool), APS (Accelerator Porosity Sonde), ECS (Elemental Capture Spectroscopy), etc. which will measure sigma (neutron capture cross section), hydrogen index (the density of hydrogen relative to that of water), neutron porosity, gas excavation effect, carbon oxygen content, etc. using thermal/epithermal neutron.

(4) Distribution of Injected CO2

Change in distribution of injected CO2 (CO2 plume) will be predicted with reservoir simulation model. Actual CO2 distribution can be detected with cross-well tomographic inversion estimating acoustic velocity distribution among wells. 4D seismic survey (repeated 3D seismic surveys) will be undertaken to monitor CO2 plume in much wider region. Permanent reservoir monitoring (PRM) with permanently installed receivers or submarine receiver cables and seismic sources (land vibroseis or marine airgun) are in early demonstration stage. Micro-seismic technology was developed to detect underground fracturing with CO2 leak through formation.

ACROSS (Accurately Controlled and Routinely Operated Signal System) was developed by a group of researchers in Nagoya University and Japan Atomic Energy Agency to survey seismic and fault activities. Field test of permanent reservoir monitoring with ACROSS system is in progress in the Aquistore CCS project in Canada. Highly reliable repeatability of seismic source signal of ACROSS system has been already proved there.

(5) Atmospheric Leakage of Injected CO2

Chugai Tecnos Co. developed continuous monitoring system for atmospheric CO2 leak, CEEMS (Chugai Environmental Effect Monitoring System) and field test of the system is in progress in the Aquistore CCS project in Canada. In CEEMS, multiple CO2 monitoring stations with independent solar power generators will be installed and data collected at each station will be transmitted with wireless communication system for monitoring CO2 leak in wide area.

(6) Monitoring Ground Deformation

InSAR (Interferometric Synthetic Aperture Radar) is the satellite technology to monitor small change in ground elevation caused by underground CO2 injection. Efficiency of InSAR technology has been proved by field test in Salah CCS project in Algeria. Tiltmeter can be utilized to detect change of ground inclination caused by underground CO2 injection.

2.5.2 Monitoring System Developed in Japan

The following systems/tools are developed for monitoring CCS projects in Japan. They are field proven or in early stage of demonstration.

Temperature, pressure and strain monitoring with fiber optic sensors, DTS (Distributed

Temperature Sensing), DAS (Distributed Acoustic Sensing), FBG (Fiber Bragg Grating), etc. Research Institute of Innovative Technology for the Earth (RITE) developed fiber optic

sensor technology for continuous monitoring of strain of casing and cement in wells in vertical (depth) direction.

Permanent Reservoir Monitoring System (PRM) with ACROSS

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Continuous monitoring of change in acoustic properties of reservoir rock with ACROSS (Accurately Controlled and Routinely Operated Signal System) is in field test stage in Aquistore CCS project in Canada.

Monitoring CO2 content in atmosphere Chugai Tecnos Co. developed continuous monitoring system for CO2 content of

atmosphere, called CEEMS and field test of the system is in progress in the Aquistore CCS project in Canada. In CEEMS, multiple CO2 monitoring stations with independent solar power generators will be installed and data collected at each station will be transmitted with wireless communication system for monitoring CO2 leak in wide area.

Ground deformation monitoring with InSAR Japan Space Systems (Jspacesystems) and Remote Sensing Technology Center of Japan

(RESTEC) are monitoring change in ground elevation using InSAR technology.

Studies and field tests of micro-seismic and cross-well tomography technologies are in progress in Japanese technical research centers.

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3． Well Abandonment Plan and Regulations

In this section, regulations of well abandonment in some countries was discussed.

Regulations of Well Abandonment in Some Countries 3.1

Oil and gas producers are abandoned when oil and gas fields are closed and the regulatory entity of most countries regulates the method of well abandonment. Followings are the applied regulation in oil industry.

Table 3-1 Regulations of Well Abandonment

Country State Regulation

Denmark A Guide to Hydrocarbon Licenses in Denmark

France Article 49 (part of Degree No. 2000-278 (RGIE,

2000)

Norway NORSOK Standard D-010

Netherlands The Mining Legislation and of the Working

Conditions Regulation

United Kingdom Guidelines for the Suspension and Abandonment of

Well by UKOOA

Australia

Western Australia Schedule of Onshore Petroleum Exploration and

Production Regulation-1991

Queensland Petroleum and Gas (Production and Safety)

Regulations 2004

Canada Alberta The Well Abandonment Guide Described in Directive

20 of the Energy Resources Conservation Board

China Control Rules on offshore Oil Well Abandonment

Operations of the People’s Republic of China

Japan Well Abandonment Regulations by the Japanese

Ministry of Economy, Trade and Industry

USA

US EPA Regulations on Plugging and Abandoning

Injection Wells for Class II wells

API guidance

Alaska The Alaska Administrative Code

California Section n1723 from the California Code of

Regulations

Texas Rule 3.14 from the Texas Administrative Code

International

Conventions

London Convention 1972 and 1996 Protocol OSPAR

Convention

Details of well abandonment and regulation in United Kingdom, Norway, and USA were discussed below as reference.

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3.1.1 United Kingdom

The regulation of well abandonment in United Kingdom is specified to onshore and offshore wells and more restricted regulation is applied to offshore wells. UK Offshore Operations Association (UKOOA) established the regulation, Oil & Gas UK Guidelines for the Suspension and Abandonment to offshore wells in 1995.

The purpose of well abandonment is to prevent the fluid flow from the reservoir to the surface or sea level through wells. Therefore, permanent well barriers must be properly set above the reservoir.

This guideline specifies the requirement of permanent well barrier as follows

Materials of permanent well barrier Number of permanent well barrier Confirmation of the integrity of well barrier Consideration of well abandonment

(1) Material of Permanent Well Barrier

Materials of permanent barrier must have following characteristics.

Low permeability to prevent flow through well barrier No degradation of materials in long term No degradation by fluid, or gas (CO2, H2S, etc.) No degradation by the temperature and pressure of wellbore No shrinking materials between casing and formation

Cement is normally used as well barrier and bridge plug or high-viscosity pills (mud) are used as additional barrier.

(2) Number of Well Barrier

At least two permanent barriers must be placed when the permeable zone is a hydrocarbon bearing zone, a high pressure zone and a water bearing zone between the surface and the formation.

(3) Requirements for Well Barrier

Position of Well Barrier 1）

Primary barrier will be placed just above the oil or gas zone. In that case, primary cement barrier must be overlapped with cement behind casing or liner. Second barrier will be backup of primary barrier and may be set considering the cement top of annulus cement.

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Figure 3-1 Position of Well Barrier

Source) Oil & Gas UK Guidelines for the Suspension and Abandonment

Figure 3-2 Position of Well Barrier

Source) Oil & Gas UK Guidelines for the Suspension and Abandonment

The position of well barriers will be determined considering geological condition such as permeable formation and cap rock. In Figure 3-2, two permanent barriers are set since there are two permeable zones (A, B) above main reservoir C.

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Length of Well Barrier 2）

The length of well cement barrier must be longer than 100 ft and 500 ft of length is practically recommended. The length of overlap with annulus cement may be recommended to 100 ft. When one cement barrier may isolate two permeable zones, following requirements are necessary.

The length of cement column (good cement) must be longer than 200 ft and practically 800 ft

is recommended The length of overlap between cement barrier and annulus cement more than 100 ft is

necessary

Figure 3-3 Length of Well Barrier

Source) Oil & Gas UK Guidelines for the Suspension and Abandonment

The example of well abandonment is shown in Figure 3-4.

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Figure 3-4 Example of Well Abandonment

Source) Oil & Gas UK Guidelines for the Suspension and Abandonment

(4) Verification of the Integrity of Permanent Well Barrier

The integrity of permanent well barrier must be verified by setting depth, seal capability, and other well condition.

Cement Barrier 1）

Integrity of cement barrier will be verified by following items.

Operation report (pumping volume, pumping pressure, returning volume, etc.) Confirmation of cement strength. Cement samples may be taken before and during

cementing job Verification of cement top by tugging of well strings Pressure test of cement barrier with 500psig higher than injection pressure of the formation

below well barrier. Applied pressure must be less than the pressure not to damage primary cement barrier.

Inflow test considering maximum differential pressure which may be supposed after well abandonment

Casing Annulus Cement 2）

The top of annulus cement behind casing must be verified. The location of top of cement will be confirmed by following methods.

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Logging (cement bond Log, temperature log, sonic log, etc.) Cementing job report (pumping volume, pumping pressure, returning volume)

Seal capability will be verified by following report.

Logging (cement bond log, temperature log, sonic log, etc.) Annulus pressure of well (pressure between production casing and intermediate casing) Leak off testing when casing shoe is drilled out Job report of cementing Density of lead cement and tail cement during cementing job and pressure behind casing

When seal capability is not concluded, additional logging or squeeze cementing must be considered.

Table 3-2 shows the guideline for the integrity of cement barrier. The location of cement barrier and the method of verification of seal capacity are shown.

21

Table 3-2 Guideline for the Verification of Cement Barrier

22

Source) Oil & Gas UK Guidelines for the Suspension and Abandonment

(5) Other Consideration of Well Abandonment

Horizontal Well 1）

The method for horizontal well abandonment is same as vertical well. The example is shown below.

Figure 3-5 Image of Horizontal Well Abandonment

Source) Oil & Gas UK Guidelines for the Suspension and Abandonment

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High Pressure and High Temperature Well 2）

The degradation of well barrier by high temperature must be considered.

Corrosive Fluid (CO2 etc.) of Formation 3）

UK guideline does not consider CCS. CO2 may possibly affect cement and mechanical plug when CO2 concentration in formation fluid is high. (The possibility of degradation by CO2 is discussed in the latter part)

Removal of Downhole Equipment 4）

Downhole equipment may not be retrieved if well abandonment follows the procedure of UK guideline.

Control Lines, ESP Cables, Gauge Cables 5）

Control lines, ESP cables and gauge cables in the well will be removed since they create the vertical leak path through well barriers.

3.1.2 Regulation of Well Abandonment in Norway (NORSOK Standards)

NORSOK standards were prepared to ensure the well integrity and applied through the life cycle of wells relative to production (drilling, completion, well testing, production, wireline job, pumping operation, well suspension, well abandonment, etc.)

(1) Well Barrier

Functions and Purposes of Well Barrier 1）

Functions and purposes of primary well barrier, second well barrier, and other well barrier were discussed below.

Table 3-3 Functions and Purposes of Well Barrier

Source) NORSOK standard D-010

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Location of Well Barrier 2）

Well barriers will be placed just above inflow source to the well. Primary and secondary well barriers will be positioned at the depth where the formation fracture pressure at the base of the barrier will be in excess the potential internal pressure.

Materials of Well Barrier 3）

Materials of well barrier must withstand the load and environmental conditions to which materials may be exposed after the time the well abandonment.

(2) Permanent Abandonment

Well barriers will be designed to any foreseeable well conditions. There must be at least two well barriers if a reservoir contains hydrocarbon or has a flow potential.

The requirements of well barrier are shown below.

To be impermeable To be integrate for long term Not to be shrinking Not to be brittle – able to withstand mechanical loads/impact To be resistant to different chemicals/substances (H2S, CO2,and hydrocarbons) To be bonding to steel To be reinforced by cement (Seal element of the mechanical plug is not a permanent barrier.) To extend across the full cross section of the well, including all annulus and sea; both

vertically and horizontally. In the right side of Figure 3-6, casing may withstand the vertical stress, however, not withstand the horizontal stress.

Figure 3-6 Well Barrier

Source) NORSOK standard D-010

Removal of downhole equipment will not be required as long as the integrity of the well

barriers is ensured. To remove control cables and lines from the areas where permanent well barriers are placed,

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since thy may create vertical leak path through the well barrier. Multiple reservoir zones and perforations located within the same pressure regime, isolated

with a well barrier in between, can be regarded as one reservoir for which a primary and secondary well barrier will be installed.

Figure 3-7 Example of Multiple Reservoir Zones

Source) NORSOK standard D-010

(3) Examples of Well Barriers

Four examples of well barriers are shown below.

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Open Hole 1）

Figure 3-8 Well Abandonment of Open Hole

Source) NORSOK standard D-010

27

Perforated Well 2）

Figure 3-9 Well Abandonment of Perforated Well

Source) NORSOK standard D-010

28

Multiple Zones with Slotted Liner or Sand Screen 3）

Figure 3-10 Well Abandonment of Multiple Zones with Slotted Liner or Sand Screen

Source) NORSOK standard D-010

29

Slotted Liners in Multiple Reservoirs 4）

Figure 3-11 Well Abandonment of Slotted Liners in Multiple Reservoirs

Source) NORSOK standard D-010

30

In above figures, Table 22 and Table 24 are referred. Table 22 shows criteria for seal capability of cement and Table 24 shows the requirement of cement plugs.

Table 3-4 Referred Table-22 in Figure 5-8 to Figure 5-11

Source) NORSOK standard D-010

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Table 3-5 Referred Table-24 in Figure 5-8 to Figure 5-11

Source) NORSOK standard D-010

3.1.3 Standards of Well Abandonment in USA

Environmental Protection Agency (EPA) established the regulation of abandonment of injectors in USA. In addition, American Petroleum Industry (API) also established the detail procedure of well abandonment.

(1) Environmental Protection Agency(EPA)

EPA classifies injectors in 6 categories.

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Class I ：Industrial and municipal waste disposal wells which inject waste water below

Underground Source of Drinking Water (USDW)

Class II ：Oil and gas related injectors

Class III ：Injection wells for solution mining

Class IV ：Shallow hazardous and radioactive injectors

Class V ：Wells for injection of non-hazardous into or above underground source of

drinking water

Class VI ：Wells for geologic sequestration of CO2

Followings are the procedure of well abandonment of class VI wells.

(1) Operator will notice the plan of well abandonment to EPA and obtain the approval no less

than 60 days before the commencement of works. (2) Operator will conduct the cleaning of wellbore, measurement of bottomhole pressure, and

testing of the well integrity. (3) Well abandonment with cement plugs will be performed.

Location of Cement Barrier 1）

The location of cement barriers will be described in the plan of well abandonment which will be submitted to EPA. The well must be plugged with cement in a manner that prevents movement of fluid from the injection zone to the base of underground source of drinking water (USDW). The recommended length of cement plug is at least 100 ft from the base of USDWs.

Figure 3-12 Recommended Well Abandonment for Class VI

Source) EPA、「Underground Injection Control (UIC) Program Class VI Well Plugging, Post-Injection Site Care, and

Site Closure Guidance, 2016

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Materials of Cement Plug 2）

Materials of cement plugs must be selected as per API standards and ASTM standards.

(2) API (American Petroleum Institute)

API standard was established in 1930’s and revised in 1952, where API classified cement in 8 categories based on the well depth.

Table 3-6 Classification of Cement in API

Source) Plugging and Abandonment of Oil and Gas Wells：National Petroleum Council , Operations and Environment

Task Group

After 1952, the standard of well abandonment was revised. Also each state in USA established its own regulation about the length and materials of well barriers based on API standard. (Table 3-1)

Permanent Well Barrier 1）

The installation of permanent well barrier must satisfy following requirements considering geologies and fluid conditions.

It withstands maximum expected load It withstands the pressure, temperature, and mechanical stress It prevents flow to outside of wells

Number of Permanent Well Barriers 2）

Number of permanent well barriers depends on the condition and number of hydrocarbon bearing zones. Primary and secondary well barrier will be placed when flow of hydrocarbon is expected.

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3.1.4 Well Integrity of CO2-EOR, SACROC (Texas, USA)

SACROC oil field is located in Permian basin, west of Texas. Field was discovered in 1952 and CO2-EOR has been carried out since 1972. CO2 storage volume is more than 67 million ton during CO2-EOR. In this field, Carey took cement samples from well 49-6 and investigated cement integrity during CO2-EOR in 2007. Well 49-6 was drilled in 1950 and was a producer in 10 years and CO2 injector in 7 years. The well was exposed to CO2 in 30 years.

Two cement samples were taken from the well. Sample No.1 was taken from 10-12ft above the injected zone and sample No.2 was taken from 1,400ft above injected zone. Properties of these samples are shown below.

Table 3-7 Cement Samples of SACROC

Source) Summary of Carbon Dioxide Enhanced Oil Recovery(CO2-EOR) Injection Well Technology

Carey observed cement samples and concluded as follows.

Both cement samples had 0.1 md of permeability and did not cause severe CO2 leak CO2 migration between casing and cement, casing and shale were observed but no CO2

migration was observed through cement. No CO2 migration was observed in the sample No.2, taken from 1,400ft above injected zone.

Cement samples showed good condition even they were exposed to CO2 in 30 years. It was expected that vertical CO2 migration was at least expected 12 ft but the detail was not

cleared. However, severe CO2 leak was not expected as cement permeability was in the rage of 0.1 md

Casing was in good condition even though some pitting was observed.

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Figure 3-13 Cement and Casing Taken from Well 49-6

Source) Long Term Integrity of CO2 Storage–Well Abandonment

Carey concluded that the cement at the SACROC 49-6 well survived and retained its structural integrity after 30 years under influence of CO2. Similar conclusion was drawn by Crow (2008) evaluating cement from a natural CO2 producer.

EPA standard regulates the procedure of well abandonment of CO2-EOR and CCS but does not regulate cement materials. API and ASTM regulate cement material based on the depth and type of reservoirs but do not regulate the requirement of well abandonment of CO2-EOR and CCS. However, it is expected that the regulation of well abandonment of EPA, API, and ASTM can be applied for CO2-EOR and CCS based on the study Carey and Crow.

Conclusion 3.2

Following points are confirmed by comparing the standards of well abandonment in some countries.

The regulations and the requirements of well barriers in UK, Norway and USA are similar. The degradation of cement by CO2 is almost negligible according to the study of cement in

SACROC CO2-EOR Unit.

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4． Study of CO2 Corrosion Protection

The corrosion protection in CO2-EOR/CCS must be considered to all facilities related to CO2 transportation, CO2 injection, production, transportation of production fluid, and gas compression. All E&P companies have its own standards about corrosion protection. In this section, the corrosion protection method in oil industries was discussed.

General Concept of Corrosion Protection in Oil Industries 4.1

Main factors which cause corrosion are following.

Corrosive components in fluid, CO2, H2S, O2 etc. Water in fluid

The corrosion rate is related to,

Flow volume, flow regime of fluid Temperature and pressure of fluid Solid content in fluid Organic acid, pH of fluid Materials of facilities

Main methods of corrosion protection are;

Removal of corrosive components in fluid Corrosion resistant materials Corrosion inhibitors Coating and painting

The corrosion protection depends on the type of facilities, temperature and pressure of fluid. Major corrosion protection in oil industries is following.

4.1.1 Evaluation of Corrosion Rate by Corrosion Prediction Models

It is important to evaluate corrosion rate of facilities which is affected by corrosive environment. Major E&P companies evaluate corrosion rate of production facilities by using corrosion prediction models and regulate corrosion protection of wells, production facilities, pipelines, etc. Following is the summary of corrosion prediction models of major E&P companies and universities.

37

Table 4-1 Corrosion Prediction Model

Source) IFE/KRE-2009/003, Guideline for prediction of CO2 corrosion in oil and gas production systems

Corrosion prediction models evaluate corrosion rate of materials (mm/yr) based on parameters like corrosion components and those concentration, pH, pressure, temperature, and flow regime which affect corrosion of materials. Operators evaluate calculated corrosion rate and select proper corrosion protection methods

4.1.2 Corrosion Protection of Wells

Wells are exposed to severe corrosion condition due to high pressure and high temperature when flowing fluid contains corrosion components. The corrosion protection of wells is generally to use corrosion resistant materials to prevent well intervention. Corrosion resistant materials must be selected considering concentration of CO2, H2S, pressure and temperature in the wellbore.

Following is the selection list of materials in NORSOK Standard M-101 used in Norway. NORSOK M-101 recommends 13Cr alloy as corrosion resistant materials in the well which produces corrosive fluid.

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Table 4-2 Material Selection for Wells

Source) NORSOK M-101

4.1.3 Flowline and Gathering Line

Produced fluid from producers will be transported to production facilities through flowlines and gathering lines. In this stage, corrosive components in production fluid will not be removed and flowlines and gathering lines are exposed to corrosive condition. The method of corrosion protection is catergorised into two methods. One is to use corrosion resistant materials and the other is to inject corrosion inhibitor into pipes. Injection of corrosion inhibitor is common because corrosion resistant materials are quite expensive.

4.1.4 Production Facilities

Produced fluid will be separated to liquid and gas through a separator. Separated gas flows to the gas treatment facility. Liquid will flow to oil treatment facility and will be separated to oil and water. After separator, corrosive components (CO2, H2S) will be mostly contained in gas phase and there is

39

very low concentration of those components in liquid phase. In case separated gas is exported, corrosive components (CO2, H2S) will be removed according to the sales gas specification and removal methods of corrosive components are classified to be chemical absorption method, physical absorption method, and membrane method. The specification of sales gas will be regulated in each country and in general, concentration of CO2 is less than 3% and concentration of H2S is less than 5 ppm. In case of Mexico, concentration of CO2 and H2S must be less than 3% and less than 4 ppm respectively according to Technical Guideline of CNH (Table 2-2).

Manifolds, separators, and acid gas removal units in production facilities are exposed to severe corrosion condition because flowing fluid contains corrosive components. In general, the method of corrosion protection is injection of inhibitors, but Corrosion Resistant Alloy (CRA) or clad steels may be used for vessels and pipes in some fields with severe corrosive conditions.

Separators are normally operated in low pressure less than 100 psig and gas compression is generally required before transmitting gas to removal units to prevent large vessel volume of removal units. Therefore, corrosion resistant materials may be used for gas compression units.

4.1.5 CO2 Injection Facilities

It is common to inject CO2 of more than 95% concentration in CO2-EOR projects. In USA, natural CO2 has been used to CO2-EOR. Natural CO2 is normally dehydrated and special corrosion protection is not necessary for transportation, compression, and injection lines of CO2-EOR. In case of CO2 recycling, if CO2 containing water is injected without dehydration, severe corrosion condition may be encountered in compression and injection facilities. In that case, corrosion protection must be considered to prevent corrosion by CO2.

4.1.6 Transportation Pipelines of Produced Gas and Liquid

The corrosion protection by materials is not practical due to the high material cost. Injection of corrosion inhibitor and cleaning of internal of pipes by pig are common.

Conclusion 4.2

Following points are confirmed in this study about corrosion protection.

The method of corrosion protection has wide varieties which are removal of corrosive

components from fluid, protection by materials, injection of corrosion inhibitors, coating and painting. To select adequate corrosion protection at various facilities, it is common to use corrosion evaluation models.

In case of wells, under corrosive conditions, well intervention will be required in order to change well equipment. Therefore, it is common to use corrosion resistant alloy (CRA) for well equipment. It is common to use CRA for producers of CO2-EOR because production fluid contains

water and CO2. In case of injectors of CO2, no special corrosion protection may be required if CO2 is

dehydrated. It is common to use injection system of corrosion inhibitors for flowlines and gathering lines.

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For production facilities like manifold, separator, acid removal unit and piping, it is common to use CRA due to the severe corrosion condition.

41

5． CCUS-Technology-Roadmap and Mexico’s Climate Change Policy

CCUS Technology Roadmap 5.1

5.1.1 General Overview

In March 2014, the Ministry of Energy of Mexico (SENER) published “Technology Roadmap in Mexico” (Roadmap), which is an outline of the orderly process to implement Carbon Capture, Utilization, and Storage (CCUS) as a means to mitigate the adverse effects of climate change. The main parts of the Roadmap detail: a) CO2 capture from fossil fuel power generation, which consists of about 19% of greenhouse gas (GHG) emissions in Mexico; b) CO2 storage by utilizing enhanced oil recovery (CO2-EOR/CCS), and; c) establishment of public policies, including the regulatory framework, which aim to be introduced before the start of commercial operation of CO2-EOR and demonstration projects of CO2 capture which are scheduled to begin around 2020. To implement the Roadmap and achieve the goal, SENER has formed a working group which it heads, and whose membership consists of the Ministry of Environment and Natural Resources (SEMARNAT), the state-owned oil company (PEMEX), Federal Electricity Commission (CFE) and research institutes. Progress of the Roadmap is as follows.

5.1.2 CO2 Capture

The Roadmap initially plans to introduce CO2 capture in fossil fuel power generation. Poza Rica natural gas combined cycle power plant in Veracruz, located close to an oil field, was selected as the site for the pilot project. Originally, the 2.4MW pilot project was planned such that it would select one post combustion CO2 capture technology using amine and to complete operations by 2019. However, because the evaluation results of top five candidate technologies had similar economic performance and they are operated along the same basic principles, in the end, three technologies, namely (Fluor (USA), Mitsubishi Heavy Industry (Japan) and BASF (Germany) were chosen for the pilot test.

After the pilot project and demonstration project (20MW) have been implemented, CO2 capture would be expanded to commercial-scale and to other CO2 emitting industries. The issues of implementation costs and incentives of CO2 capture must be resolved by that time.

42

Figure 5-1 CCUS Technology Roadmap in Mexico (CO2 capture from Power Plants)

Source) SENER“CCUS Technology Roadmap in Mexico”

5.1.3 CO2 Utilization and Storage

In order to attract international technologies and funding for CCUS, SENER is planning to utilize the carbon market. In 2016, SENER conducted an assessment on requirements for a CO2-EOR project in order to assure permanent storage of CO2 to generate carbon credits. The assessment report suggests that the operator must secure permanent geologic storage of CO2 and conduct additional monitoring, reporting and verification (MRV) of CO2 movement to track and demonstrate CO2 storage beyond typical EOR operations. As for the MRV, the report recommends a tiered approach based on the risk identified. Primary requirements include the need to monitor the reservoir zone to adequately track pressure, temperature, and CO2 movement. Should leak signals be detected, the second tier of MRV is to monitor the above-zone and the third tier is to monitor the near-surface and surface. The Roadmap also details how monitoring is one of the important points from the viewpoint of providing confidence to the public about CO2 storage reliability.

Figure 5-2 CCUS Technology Roadmap in Mexico (CO2-EOR)

Source) SENER“CCUS Technology Roadmap in Mexico”

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5.1.4 Public Policy

(1) Regulatory Framework

The other important point when considering CCUS is a regulatory framework which includes the MRV of CO2 storage and liability of CO2 leak. SENER, with the support from World Bank, has made an in-depth assessment of the regulatory framework in Mexico and identified necessary revisions in order to implement CCUS projects. The World Bank references the regulations of other countries, such as Australia, Canada, USA and EU, which have already developed comprehensive regulatory frameworks for CCUS activities. After checking 38 key issues (see below), several recommendations from the aspect of CO2 capture, transport, storage (in and outside of the hydrocarbon sector), long-term liability of CCUS activities and environmental protection/climate mitigation have been made. The Mexican government is currently considering how to reflect these recommendations in the current legal framework and will then make any necessary amendments before the commencement of commercial operation of CO2-EOR project.

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Table 5-1 List of Key Issues for the Development of Regulatory Framework for CCUS

Source) SENER “Development of a regulatory framework for carbon capture, utilization and storage in Mexico”

(2) Generate Carbon Credits from CCUS Projects

In order to promote CCUS projects, which by themselves are not economically attractive, the Mexican government is preparing to apply carbon markets to the CCUS projects that would then enable them to attract international funding. However, CCUS projects do not generate carbon credits easily due to the requirements for a long-term and usually expensive MRV after the CO2 storage, and the establishment of regulatory framework for CCUS activities in the host country, among other

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reasons. So far, there are no carbon credits that have been generated from CCUS projects globally. Even UNFCCC (United Nations Framework Convention on Climate Change), which has been discussing CDM rules for CCUS projects for many years, has not developed a CCUS methodology to date, except for a CO2-EOR methodology registered by the American Carbon Registry.

In July 2014, Mexican and Japanese governments signed the Joint Crediting Mechanism (JCM) agreement. Since then, four feasibility studies for CCUS projects, which include the development of a draft methodology of CO2-EOR projects, have been implemented under the Japanese government’s subsidy program. The Ministry of Economy, Trade and Industry (METI) expects to develop CO2-EOR projects under the JCM scheme.

* CDM: Clean Development Mechanism. An emissions reduction mechanism under the Kyoto Protocol, United Nations Framework Convention on Climate Change.

Figure 5-3 CCUS Technology Roadmap in Mexico (Public Policy)

Source) SENER“CCUS Technology Roadmap in Mexico”

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Mexico’s Climate Change Policy 5.2

5.2.1 Mexico’s GHG Emissions and Reduction Target

(1) GHG Emissions

Mexico’s GHG emissions in 2013 were 665million t-CO2e, out of which 173million t-CO2e was CO2 removals from forested lands. Thus, net emissions were 492million t-CO2e. This represents a GHG emissions increase of 40% in 2013 when compared to 1990. During the period 2002-2012, GHG emissions’ average annual growth rate was 2.5%, whilst average annual growth of GDP for the same period was 2.4%, which could be an indication that emissions in Mexico and GDP have not yet decoupled. However, the amount of GHG emissions has decreased for two consecutive years since 2012 while GDP is growing, which also means the trend might be changing.

Figure 5-4 Mexico’s GHG Emissions by Economic Sector and Gas

Source) UNFCCC “Mexico’s Climate Change Mid-Century Strategy”

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Figure 5-5 Mexico’s GHG Emissions Trends

Source) UNFCCC ”Mexico’s Climate Change Mid-Century Strategy”

(2) GHG Emissions Reduction Target

Mexico, which ratified the Paris Agreement in September 2016, committed to reduce its GHG emissions by 22% and black carbon by 51% below its business as usual scenario by 2030, and to further increase its GHG emissions reduction to 36% and black carbon to 70% if the global agreement, including international cooperation on financial resources and technology transfer, can be achieved. (Business as usual in 2030 is GHG 973million t-CO2e and black carbon 137million t-CO2e) These targets are based on the premise of net GHG emissions peaking in 2026, carbon intensity per unit of GDP decreasing by around 40% and the share of in-country clean energy utilization increases to 43% by 2030.

（単位：TgCO2e）

Figure 5-6 Mexico’s 2030 GHG Mitigation Target Source) UNFCCC “Mexico/Intended Nationally Determined Contribution 2020-2030”

In November 2016, Mexico also submitted a long-term climate change strategy to UNFCCC in

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response to UNFCCC’s request that all countries submit a long-term strategy by 2020. Mexico’s “Climate Change Mid-Century Strategy” aims to reduce 50% of national GHG below 2000 level by 2050, which means GHG emissions will be around 313million t-CO2e by 2050.

Figure 5-7 Mexico’s GHG Mitigation Scenarios

Source) UNFCCC “Mexico’s Climate Change Mid-Century Strategy”

5.2.2 GHG Emissions Reduction Policies

(1) General Overview

The General Law on Climate Change, launched in October 2012, is the basis of Mexico’s climate change policy. The law aims for a competitive and sustainable low emissions society which sets; GHG reduction target: 30% below business as usual by 2020 and 50% below 2000 level by 2050 Clean energy generation ratio: increase to 35% by 2024 (* Renewable energy in 2014 was

17.6%) National Emissions Registry: large GHG emitters obliged to report annual GHG emissions

amount Emissions trading system: Establish a voluntary emissions trading system and link or utilize the

credits in overseas carbon markets.

The law stipulates to review the GHG emissions reduction policy every 10 years and adaptation policy every 6 years.

(2) National Emissions Registry (RENE)

In line with the General Law on Climate Change, companies and facilities in the energy, transportation, waste, agriculture and service sectors which emit GHG (CO2, CH4, N2O, SF6, PFCs, HFCs, NF3) and black carbon over 25,000 t-CO2 per year directly or indirectly are required to report the emissions amount annually and the report be verified every 3 years from 2015. Carbon credits generated from domestic projects can also be voluntarily registered in the Registry.

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(3) Carbon Tax

Since 2014, the Mexican government has imposed a tax on production or import of fossil fuel, excluding natural gas. Carbon tax was set at 3.5USD/t-CO2e (39.80 peso/t-CO2e) and capped at a maximum of 3% of the unit sales price resulting in the expectation of about 1 billion USD of extra annual revenue by the government. The interesting point of this scheme is that the taxpayer can use CERs to replace part of their Carbon Tax. They can deduct the amount of CERs, valued by the market price at the time of tax payment, from the total amount of the tax. Detailed rules are currently being discussed.

Table 5-2 Carbon Tax (by types of fossil fuel)

Source) SEMARNAT “Carbon Tax in Mexico”

(4) Clean Energy Certificate (CEL)

The Mexican government established a Clean Energy Certificate (CEL) program to facilitate investments in renewable energy in order to achieve the target of renewable energy contributing 35% of the total energy consumption by 2024 and 50% by 2050, which is stipulated in the Electricity Industry Law launched in August 2014. CEL will be issued at 1 unit to 1kWh of clean energy generated from renewable energy and for cogeneration which starts its operation after August 2014 and has a 20 year-generation capacity. These CELs will be purchased by large power consumers and retailers who are required to consume/purchase a certain share of clean energy and prove their achievement of the target by surrendering CELs to the government an amount equal to their obligation. Large power consumers and retailers can purchase CELs from clean energy suppliers or from the wholesale market. The issuance of CELs and the clean energy targets will start from 2018 and the clean energy targets will be decided three years prior to the obliged year. The obligation of 2018 is more than 5% of total power demand and rises to 5.8% in 2019.

(5) Emissions Trading System (ETS)

While the CEL program is a regulation for indirect CO2 emissions, the Mexican government is

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planning an emissions trading system (ETS) commencing in 2018 covering direct GHG emissions by industries. As discussed above, companies are already obliged to report GHG emissions amount annually through RENE. In 2017, SEMARNAT will implement a simulation of the ETS so that the companies can get used to the new system. Target sectors are power generation, oil & gas, cement, paper & glass, chemical, transport, among others. During the one-year simulation, the degree of difficulty gradually increases in a cycle of every 2-3 months and will end with the application of the Californian ETS/Quebec ETS rules, which the Mexican government is looking to link with in around 2020. By implementing the simulation, participants and government can learn/discuss what kind of system fits best in Mexico.

To those sectors where ETS is not applied, the Mexican government is planning to apply emissions reduction system and export carbon credits generated in order to also promote emissions reduction in these sectors. In July 2014, the Mexican and Japanese governments signed a bilateral JCM agreement. Since then, a total of 13 feasibility studies, including CO2-EOR and energy efficiency projects, and one JCM project have been implemented in Mexico. Carbon credits generated from JCM projects can be exported to Japan or be used in the Mexican ETS. In addition, carbon credits generated from emissions reduction projects in Mexico can also be exported to the Californian ETS/ Quebec ETS, but this depends on rules of the linkage.

Observations 5.3

It needs to be noted that there is a certain difficulty with respect to who along the CCUS project value chain will recognize the CO2 emissions reduction benefit. In a CCUS project, CO2 capture and CO2 storage (CO2-EOR) have different operators. While the CO2 capture operator will capture the CO2 emitted and be able to claim to have reduced emissions, this benefit in turn gets transferred to the CO2-EOR operator once the CO2 is sold to this operator. If the CO2-EOR operator then sells carbon credits generated from the CO2-EOR project, the benefit of emissions reduction is once again transferred to the buyer of the carbon credits. From an economic standpoint, the CO2-EOR operator gains from oil sales produced as a result of the CO2-EOR. Thus for the CO2-EOR operator, if the price of oil and value of carbon credits is above a certain level, then the cost of monitoring for CO2 storage could be covered.

However, there are fewer incentives for the operator of CO2 capture, whose economic benefit from CO2 capture results only from the sale of CO2 to the CO2-EOR operator while the capture cost of CO2 remains expensive. (According to a study by Research Institute of Innovation Technology for the Earth (Japan), CO2 capture cost from gas power plants using amine is more than 65USD/t-CO2.) As an incentive to address this economic imbalance for power plants which capture CO2, the Mexican government is considering granting CEL to them. If CEL is priced at 24USD per unit (CEL price of CFE’s first auction held in 2016) and the emission factor of gas power generation is 0.376t-CO2/MWh, the value of CEL granted would be 64USD/t-CO2 and could cover most of the costs of CO2 capture.

Another issue is that the operators of CO2 capture who will emit CO2 that, for whatever reason, may fail to be captured, would be subject to ETS and are then obliged to reduce CO2 further or purchase CO2 emission allowances if they are unable to meet the target. However, the value of CO2 emissions reduction would already have been transferred to the CO2-EOR operators when CO2 was sold to them. If the government were to decide to grant CO2 emission allowances for CO2 captured, as in the case of CEL, it could in turn cause an issue of “double counting” of CO2 emission reduction,

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especially when Mexican ETS is eventually linked with Californian ETS/Quebec ETS and the granted CO2 emission allowances are transferred overseas. Another idea is to assume CO2 capture equate to CO2 emissions reduction even if the value has been transferred to CO2-EOR operator. However in this case, no economic value would be generated for the operator and the government may thus need to consider some additional incentives.

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Feasibility Study project for the JCM (2016FY) Technical Study for application of JCM to CCS at onshore oil field in Mexico March, 2017

Toyo Engineering Corporation Energy Business Unit

TEL (047)454-1725