CO₂ Storage via In-situ Mineralization in Mafic and Ultramafic Formations

This Module details durability and monitoring requirements for storage of CO₂ removed from the atmosphere and stored via in-situ mineralisation in mafic or ultramafic rock formations.

CO₂ injection into mafic or ultramafic formations, such as basalts, peridotite and ophiolites, accelerates the natural chemical reaction of mineral carbonation that permanently immobilizes CO₂ in the subsurface¹. Injected CO₂ first dissolves in water before reacting with divalent cations (Ca²⁺, Mg²⁺, and Fe^2+/3+) in the reservoir rocks to form carbonate minerals (e.g., calcite - CaCO₃). This process has been demonstrated to rapidly store the majority of injected CO₂ within two years of injection at field pilots in Iceland^{2, 3} and the USA^{4, 5}. CO₂ can be injected as a supercritical fluid or dissolved in water. Dissolution of CO₂ into a water phase can occur at the surface, in the injection well, or in the reservoir into formation fluids. Injecting pre-dissolved CO₂ (either prior to or during injection) will lower loss of durability risks and result in faster mineralization rates compared to supercritical CO₂ injection. This is because dissolving CO₂ in water eliminates the buoyancy of CO₂ by creating a dense solution (CO₂ saturated water) that sinks when injected into the storage reservoir⁶. To ensure sufficient durability, CO₂ characteristics and the conditions within the storage reservoir must be well defined, modeled and monitored. Once CO₂ is trapped within the reservoir, and there is proof of no free phase migration outside the intended target reservoir or to Underground Sources of Drinking Water (USDWs) after closure (as per regulating permitting requirements), the CO₂ can be considered ‘permanently’ removed. Geochemical measurements will be critical for demonstrating and quantifying mineralization.

This Module is applicable to dissolved or supercritical CO₂ injection into onshore mafic or ultramafic formations (e.g., basalts and ophiolites) that will allow for rapid in-situ CO₂ mineralization. Crediting will occur on injection into the reservoir and isolation from the atmosphere.

This section outlines requirements for evaluating CO₂ injection and storage within mafic and ultramafic systems for mineralization, with a focus on site characterization, construction and monitoring. The post-injection monitoring plan detailed in Section 3.2 acts to address and mitigate these potential risks to durability. Section 4.0 addresses accounting for any emissions associated with these risks.

Monitoring of the injection site needs to be completed to ensure that any injected CO₂ remains stored within the confines of the geologic reservoir and does not migrate outside of the reservoir limits, nor convert into gases that may later be re-emitted (e.g., CO₂, CH₄). The injection site must be monitored in accordance with the country/region’s specific well permitting requirements as specified in the operating permit issued for the injection site. Each site should create a “testing and monitoring plan” which incorporates available, site-specific techniques that support the overall goals of detecting trends or events that might lead to endangerment of USDWs and demonstrates that The Project is operating as permitted. This plan should be submitted to Isometric.

The subsurface monitoring approach developed and implemented by the Project Proponent must address the parameters laid out below, via the permitting process and permit compliance, or by additional efforts and documentation.

• Geologic Reservoir and Site Characterization: the proposed storage site must have been properly characterized to demonstrate site suitability for mineralization and containment of CO₂ (See Section 2.2 for further details).
• Injection Site Construction and Performance: the proposed storage site and injection system must be properly designed, including design and specification of wellbore and well materials to ensure proper long term operation of the well when injecting CO₂ and protection of any potable aquifers.
• Injection System Operation & Monitoring: the Project Proponent must specify operating conditions and monitoring systems and approaches, such as allowable wellhead pressures, CO₂-water ratio (for dissolved CO₂ injection), gas detection, and other systems to ensure that injected CO₂ remains in the [geologic formation], the formation is not negatively impacted by operations, automatic safety precautions are in place to minimize potential for exceeding allowable operating conditions, and conditions can be monitored for compliance or deviation from requirements. Reporting of operations will be in accordance with the governing body.
• Closure and Post-Closure Requirements: Requirements for proper closure of the storage reservoir and injection facility, as well as post closure requirements and post-injection monitoring to ensure CO₂ is mineralized and remains sequestered durably in the storage reservoir, the site is properly monitored, and any non-compliance is addressed with corrective actions.

Specifically, the requirements in this Module must be met to ensure durable storage of CO₂ in the geologic reservoir.

Potential risks to expected durability are site specific, but may include:

• Risk A: Migration of free phase CO₂ outside of the intended formation.
  • For supercritical injection, the CO₂ plume will migrate within the reservoir and the injected plume could migrate further or have more limited dissolution than reservoir models initially predicted. Reservoir models and injection procedures should be updated during monitoring to specify injection and reservoir management parameters, ensuring containment of the CO₂ within the target reservoir.
  • Breach in well integrity leading to CO₂ leaks into the overlying formation. Injection, monitoring, and well integrity testing procedures should be updated during monitoring in order to ensure well integrity.
  • Migration of dissolved CO₂ into the overlying formation may also result in CO₂ exsolution due to the decreased hydrostatic head.
• Risk B: Induced seismicity can change reservoir properties
  • The injection of CO₂ and water can induce seismicity within a reservoir which can alter the reservoir connectivity and flow paths. This risk may be a greater risk when injecting dissolved CO₂ due to the large volume of fluid that would need to be injected into the subsurface. Prior to any injection [activity] a site-specific study of the regional seismicity must be performed.
• Risk C: Formation of a gas phase
  • Changes in reservoir pressure and temperature could result in the exsolution of some gaseous CO₂.
  • CO₂ could be microbially consumed to form CH₄⁷. This risk is thought to be greater for supercritical CO₂ injection ⁷.
  • Indicators of CO₂ exsolution and biogas production should be monitored as part of the post-injection monitoring plan (see Section 3.2) Any gases produced will be considered removed if one or more confining layers are present that prevent the vertical migration of buoyant phases. Any releases of gases from the storage reservoir must be accounted for as reversals (see Section 4.0).
• Risk D: CO₂ injection results in leaks in injection, monitoring or legacy wells.
  • CO₂ can damage integrity of any injection monitoring wells.
• Risk E: Redissolution of carbonates already precipitated as injection continues.
  • The injection of CO₂ will decrease the pH within the reservoir and potentially result in the dissolution of carbonates that have previously been mineralized. This CO₂ will be dissolved and thus more mobile than in carbonates. For supercritical CO₂ injection, the reservoir must have a confining layer to ensure that CO₂ will be contained and durably stored. For dissolved CO₂ injection, which is much less mobile, the reservoir will also ideally have a confining layer, however where this is not present, further site charaterization and additional geochemical monitoring and pressure will be required. Furthermore, it is likely that this CO₂ will be remineralized downstream ensuring durable storage ².
• Risk F: Mineralization causes a loss of permeability and/or decrease in pore space.
  • As mineralization occurs, injectivity to the storage reservoir could decrease due to a loss of permeability and pore space, particularly if mineralization occurs close to the injection wellhead. In this scenario, the reservoir capacity for CO₂ storage will decrease, but the durability of CO₂ that has already been injected and mineralized will not be impacted.
• Risk G: Trapping rates are lower than predicted
  • Mineralization within the reservoir could be less than initially predicted in reservoir models as a result of a limited supply of cations and/or reactive surface area. In this scenario, injected CO₂ would remain mobile either as a supercritical liquid or dissolved in water. As long as the reservoir has an impermeable confining layer or remains dissolved within the mineralization zone, CO₂ will be considered contained and durably stored. Any releases of this injected CO₂ from the storage reservoir must be accounted for (see Section 4.0).
  • For supercritical CO₂ dissolution rates may also be lower than initially predicted in reservoir [models]. In this scenario, injected CO₂ would remain mobile either as a supercritical liquid or gas phase. As long as the reservoir has an impermeable confining layer, CO₂ will be contained and durably stored. Any releases of this injected CO₂ from the storage reservoir must be accounted for (see Section 4.0).

Projects must submit at least one address and/or specific geo-coordinates for the project. Projects may submit multiple project locations - please specify the operations occurring at each project location.

The injection site must have a current well permit issued by the responsible authority for the location of the injection facility and reservoir, for example within the USA a Class VI well permit from the EPA or authorized primacy state level governing agency is required. The permit must specifically identify CO₂ as acceptable injectants under the permit. In addition, The Project must comply with all applicable local environmental, ecological and social requirements as well as those set out in the relevant Protocol and the Environmental and Social Impacts Section of the Isometric Standard. For CO₂ mineralization the geologic reservoir must allow for rapid in-situ carbonate mineralization. If there is a possibility that the reservoir could be impacted by enhanced hydrocarbon recovery (EHR or EHR+) operations, storage will not be permitted.

Projects operating with an approved permitting regime (see Appendix B) should comply with the requirements of this Module and of the permit. Where monitoring parameters in this Module defer to the permit, the permit requirements must be disclosed to Isometric within the Project Design Document (PDD) and followed throughout The Project. Permit compliance can only be used as evidence for requirements that align with this module and have permit compliance as an evidence option. If a requirement does not allow permit compliance as evidence, the required evidence must be submitted.

For projects operating in locations outside of these permitting regimes, the Project Proponent must ensure that they meet the requirements of this Module and are equally as rigorous as the permits listed above. This monitoring plan must be signed off by a licensed geoscience professional (Professional Geologist (PG/P.Geo), Chartered Geologist (CGeol), European Geologist (EurGeol), or equivalent; suitably experienced in subsurface work and/or in CO₂ storage (or analogous saline/gas storage). The sign-off is to confirm the plan is sufficient for the site, and the signed report must be submitted to Isometric as part of the PDD. Specifically, the reviewer should sign off on: (1) site characterization report; (2) Area of Review (AOR)and reservoir modeling with [uncertainty]; (3) risk register and mitigation plan; (4) Monitoring/Testing/Reporting plan; (5) well-integrity plan; (6) demonstration of rigor equivalent to the listed permits; and (7) CO₂ Storage Resources Management System (SRMS) maturity opinion.

All projects are required to clearly report the regulations for which are utilized at the site, with any deviations from the relevant national/international standards outlined within the PDD upon submission to the relevant validation & verification body (VVB).

For Projects with an Approved Permitting Regime and in good standing with the permitting authority, monitoring requirements which identify "Approved Permit" under Evidence Reporting (see Monitoring Requirement Tables in Appendix 1) may be satisfied through submissions to the permitting authority.

The Storage Operator must maintain copies of all data and evidence submitted to the permitting authority against these requirements and must provide such records to Isometric and the VVB within 30 days of submission to the permitting authority, or upon request.

For monitoring requirements not covered under the Approved Permit, the Project Proponent remains responsible for collecting and reporting all required data directly to Isometric and the VVB according to the frequencies and standard reporting timelines specified in this module.

In the case of changes to the permit requirements, permitting authority, and/or regulatory environment, the Project Proponent must notify Isometric and the VVB immediately of any changes which may impact monitoring requirements. Monitoring plans will be subject to reevaluation following such changes.

Site characterizations must include evaluation of reservoir chemistry and conditions where required to ensure CO₂ will be stored within the reservoir. The permit must define the Area of Review (AOR) for the site in accordance with the requirements for the specific well class, formation, and local characteristics.

The Project Proponent must demonstrate and justify that the CO₂ and injection process result in long term stability and limited lateral migration such that the CO₂ stays within the target formation and does not impact the USDWs or above-surface environmental conditions. The Project Proponent must demonstrate that the geologic system:

• Includes a mineralization zone of sufficient volume, porosity, permeability, and injectivity to receive the total anticipated volume of the CO₂ and to facilitate CO₂ migration.
• Has sufficient divalent cations (Ca²⁺, Mg²⁺, and Fe^2+/3+) available for the CO₂ mineralization process within the mafic or ultramafic rocks, for example at Carbfix this number is ~25 wt%⁸ while in the Columbia River Basalts it is ~16 wt%⁹ and peridotites is >50 wt% ¹⁰.
• Has a sufficient reactive surface area for the reactions to take place, or a plan to engineer an increase in surface area to allow for the reactions.
• For supercritical CO₂ injection, includes a confining system free of transmissive faults and fractures and of sufficient extent and thickness to contain the injected supercritical CO₂ and any gas generated if applicable. It should also allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); the confining system will prevent vertical migration of CO₂, brine or any gas generated above the storage complex, towards the surface and atmosphere and/or USDWs;
• For dissolved CO₂ injection, includes a confining layer (of sufficient thickness with a known and appropriate entry pressure and reactivity) and/or has sufficiently characterized the mineralization zone and overlying lithologies (including permeability, reactivity and transmissive faults and fractures) to understand all possible fluid migration pathways that need to be monitored.
• Will not be impacted by, or induce as a result of the injection process, seismicity at levels that may inhibit the durability of CO₂ storage due to changes in the formation structure. If this seismic risk exists, the Project Proponent will establish criteria within the regulators permit that require relevant seismic monitoring or preventive limitations on injection for example using the same or similar traffic light system as was designed for Reykjavik Energy¹¹.
• Bubble point pressure must be calculated, using appropriate geochemical tools (e.g., PHREEQC software version 3), thermodynamic databases and equations of state (e.g., Peng-Robinson). It must include consideration of the:
  • Mass flow rate of the CO₂ stream entering the injection well.
  • Mass flow rate of the water stream entering the injection well.
  • Temperature of the water stream entering the injection well.
  • Temperature of the CO₂ stream entering the injection well.
  • Elemental/gas/dissolved gas composition of the CO₂ stream entering the injection well.
  • Elemental composition of the water stream entering the injection well.

These can be demonstrated by laboratory testing of reservoir rocks/cores (e.g., to measure cation availability) or geochemistry, literature data and/or field based approaches such as a pilot injection and to demonstrate solubility and mineral trapping). The laboratory experiments may also include quantification of the rate of CO₂ mineralization. A relevant core could be a representative rock sample from a sister reservoir, or equivalent, but ideally be a core directly sampled from the project site.

This shall be used to create reservoir models/simulations to demonstrate if the reservoir is favorable, by assessing dissolution, migration and expected mineralization and quantifying the expected extent of each process. These models must include an evaluation of potential behaviors from accurate representation of the geological storage complex (i.e., geostatic model), and a geochemical model representing the possible behaviors of the CO₂, rocks, minerals and other fluids within the system. Combined or separate reactive transport models are recommended.

The Project Proponent must conduct a baseline characterization of the AOR using parameters that include but are not limited to those set out in Table 1.

Table 1: List of baseline characterization requirements

Site characterization and predictive reservoir models must be reviewed every 5 years as part of the Crediting Period and regulators permit renewal application minimum, or at the request of the regulating programs Director, or when monitoring and operational conditions warrant, as indicated by a significant change in site conditions or injectant characteristics, based on monitoring data. The review must include a comparison of pre-injection project assumptions and reservoir models to actual measured conditions including plume size, extent, and migration, where possible, and specific operating conditions observed during injection. Estimates revised with any acquired monitoring data should demonstrate that the planned injection volume will remain within the storage complex until the end of the post-injection monitoring period.

Project validation and verification must incorporate site visits to project facilities in accordance with the requirements of ISO 14064-3, 6.1.4.2, including, at minimum, site visits during the first Validation or Verification of a Project, to the capture and (if applicable) storage site. Verifiers should whenever possible observe operation of the capture and storage processes to ensure full documentation of process inputs and outputs through visual observation and validation of instrumentation, measurements, and required data quality measures.

A site visit must occur at least once during each project validation. Additional site visits may be required if there are substantial changes to field operations over the course of a project's validation period, or if deemed necessary by Isometric or the VVB. Site visit plans are to be determined according to the VVB's internal assessment, in consultation with Isometric.

The Project Proponent must ensure that the injection well is constructed in compliance with the regulator’s permit and according to national or international best practices, and documentation and records of well construction are maintained and available for review.

At a minimum, the Project Proponent must ensure that all injection, observation or monitoring, legacy offset and production wells contained within the delineated AOR have been evaluated. Extra caution should be used on wells which penetrate into the mineralization zone. Wells which pose a risk to durability have been plugged prior to injection in order to:

• Prevent the movement of fluids into or between any unauthorized zones
• Prevent the movement of fluid into USDW
• Permit the use of appropriate testing devices and workover tools
• Permit continuous monitoring of the injection well pressure in the annulus space between the injection tubing and long string casing

Casing, cement, tubing, packer, wellhead, valves, piping, or other materials used in the construction of each well associated with The project must have sufficient structural strength and be designed for the life of The project. All surface casing will be set below the lowermost USDW and cemented to the surface. All well materials must be compatible with fluids with which the materials may be expected to come into contact, including CO₂ and formation fluids (e.g., corrosion-resistant well casings and CO₂ resistant cement) and must meet or exceed standards developed for such materials by API, ASTM International, or comparable standards.

The casing and cementing program must be designed to prevent the movement of fluids out of the mineralization zone and above the storage complex.

Monitoring of injection, system integrity as well as for subsurface migration is required in order to identify and measure potential leaks and/or validate update models as appropriate.

The Project Proponent will ensure that the injection facility complies with the well permit, including the development and implementation of the well operating plan as required by the permit. If the permit (for projects within an approved permitting jurisdiction) or approved monitoring plan (for those outside of these jurisdictions) has different monitoring requirements to those stated here, please provide justification of any deviation within the PDD. This plan should be updated every five years, unless the regulatory body that issues the permit requires this to be updated more often, to take account of changes to the assessed risk of CO₂ leaks, changes to the assessed risks to the environment and human health, new scientific knowledge, and improvements in best available technology. The risks (see Section 1.1) addressed by each measurement will be denoted in a square bracket. At a minimum, the permit and associated well operating plan must consider the following:

• Maximum allowable surface injection pressure (MASIP) at the injection wellhead that is allowed during injection operations to prevent fracturing of the formation, set according to the regulators permit. Injection operation pressures must reflect local regulatory agency requirements for formation fracture pressure as a precaution to ensure that the geologic formation will not be fractured [B].
  • Installation and use of continuous recording devices to monitor injection pressure and the pressure on the annulus between the tubing and the long string casing. Injection pressure may be defined either at the wellhead (i.e., wellhead pressure) or downhole (i.e., bottomhole pressure).
  • Monitoring and documentation of operational parameters (injection pressure, rate, and volume, the pressure on the annulus, and the annulus fluid volume) through the use of continuous recording devices, using methods including but not limited to acoustic and nuclear methods and temperature and pressure measurements. Records of these must be maintained for review.
• The pressure when the injected CO₂ stream enters the storage reservoir. This should be greater than the bubble point pressure¹² of the dissolved CO₂ (under reservoir conditions). This is to ensure a reservoir pressure >5 bar higher than the bubble point pressure and enable immediate and complete solubility trapping of CO₂¹³ [A, G]. Reservoir pressure can either be measured at the bottom of the well or calculated using the hydrostatic pressure gradient for the AOR reservoir and water table depth.
  • Bubble point pressure must be calculated at least monthly, using appropriate geochemical tools (e.g., PHREEQC software version 3), thermodynamic databases and equations of state (e.g., Peng-Robinson). It must include consideration of the:
    • Mass flow rate of the CO₂ stream entering the injection well.
    • Mass flow rate of the water stream entering the injection well.
    • Temperature of the water stream entering the injection well.
    • Temperature of the CO₂ stream entering the injection well.
    • Elemental/gas/dissolved gas composition of the CO₂ stream entering the injection well.
    • Elemental composition of the water stream entering the injection well.
• Maximum CO₂ injection rate to monitor volumes injected, prevent induced seismicity or return of injectant. In the case of dissolved CO₂ injection, this will also monitor the CO₂-water ratio (and the rate of each) to ensure all CO₂ dissolves. Injection volumes should be reported at a minimum yearly to the competent authority [B].
  • Installation and use of continuous recording devices to monitor injection rate and volume and/or mass (see Section 5.3).
  • Monitoring and documentation of injection rate must be performed and records maintained for review. This should also be used to calculate the cumulative volume of CO₂ injected.
• Analysis of the CO₂ with sufficient frequency to yield data representative of its chemical and physical characteristics, using industry standard or indicated methods and quality and properly calibrated equipment [D, E]:
  • pH and temperature
  • Viscosity
  • CO₂ concentration (i.e., wt% CO₂, C content). More information on these measurements can be found in Section 5.2.
  • Gas/dissolved gas composition including impurities that might alter corrosivity, properties of the injectate downhole, or reactivity with the reservoir rocks/fluids (e.g., arsenic, hydrogen sulfide, mercury).
  • Density of dissolved CO₂ and water mixtures.
  • Reactive or non reactive tracers used. See Section 3.1.3.2) for more details.
  • Major ions within dissolved CO₂ streams.

Additional measurements may include:

• δ¹³C of the CO₂/DIC (if dissolved).
• Minor ions within dissolved CO₂ streams.
• $δ^{18}$O, $δ$D within dissolved CO₂ streams.

Injectate monitoring is required at a sufficient frequency to detect changes to any physical and chemical properties that may result in a deviation from the permitted specifications. For supercritical CO₂ samples may need to be extracted from the pipeline or wellhead via a valve and permitted to decompress into a gaseous phase within a sample holder or other device for analysis. The injectate composition throughout the year should be reported at a minimum once a year to the competent authority.

Wells must have species-specific gas detectors (or equivalent sensors/imaging) capable of detecting, at minimum, CO₂, CH₄ and propane (C₃H₈), with alarms and injection shut-off systems (e.g., automatic shut-off or procedures in place for manual shut off of injection/operation), including injection pump shutoff when maximum pressure is reached or maximum flow rate is exceeded. Where site-specific risk assessment identifies additional species of concern (e.g., H₂S, VOCs, other hydrocarbons), detection capability for those species must also be provided. The Project Proponent must justify the selected detector type(s) and their suitability for the site conditions in the PDD [C].

Detectors/alarms may be placed on the injection wellhead or a monitoring well.  If gas is detected, continuous detection must be established at the wellhead and any producing or monitoring wells. The determination that detected gas is attributable to project operations must be made by the Project Proponent and reported to Isometric and the VVB [C].

If gas detection alarms are activated at any monitored well, a "Triggered Gas Investigation" is initiated (Section 3.1.3.1). The Operator must immediately investigate and identify as expeditiously as possible (or in accordance with permit requirements) the cause of the alarm or shutoff, and report the instance to Isometric. Where a Triggered Gas Investigation (Section 3.1.3.3) is already active, individual alarm events must be logged and reported but do not require a separate investigation unless they indicate a materially different or escalating condition [C].

• Corrosion monitoring must be performed and reported quarterly. This includes identifying any loss of mass, thickness, cracking, pitting, and other signs of corrosion), to ensure that well components meet the minimum standards for material strength and performance set by API, ASTM International, or equivalent. In addition, any monitoring wells should also be monitored for their internal integrity [A, D].
• A demonstration of external mechanical integrity annually beginning prior to injection until the injection well is plugged. This could include but is not limited to: an oxygen activation log, temperature log or sensors (e.g., distributed temperature sensors), or noise log. If one test indicates the potential loss of mechanical integrity, follow-up tests can verify and further characterize the potential pathways for leaks [A, D].
• A pressure fall-off test, every 2 years [A, D].
• Continuous monitoring of pressure within the wellbore annulus [A, D].

As applicable based on specific site conditions, formation type, and permit class, monitoring to ensure CO₂ migration beyond the AOR has not occurred. Changes versus baseline conditions and/or modeled behavior/predictions may indicate CO₂ related migration or irregularities. These should be used to assess whether any corrective measurements are taken and used to make an updated assessment of the durability of the reservoir both in the short and long term.

Near surface monitoring, where required by permit, should be completed at a site-specific frequency and spatial distribution in order to monitor any CO₂ movement to above the reservoir seal and potential impact USDWs [A]. This includes monitoring of:

• CO₂ concentrations around the wellhead and personal CO₂ detector on all operators.

• Surface gas, including CO₂, H₂ and CH₄, concentrations and fluxes to identify large point-source leaks. Spatial distribution must be determined using baseline data. Monitoring can be completed using one or more of the following methods:

  • Optical CO₂ sensors, such as airborne infrared spectroscopy, non-dispersive infrared spectroscopy, cavity ring-down spectroscopy or LIDAR (light detection and ranging)
  • Eddy covariance (EC) flux measurement at a specified height above the ground surface
  • Portable or stationary carbon dioxide detectors
  • Tracer testing using inherent tracers such as radon, noble gases, and $δ^{13}$C of CO₂/CH₄, provide a unique fingerprint for the CO₂ or associated gases that can be identified in aboveground emissions.

• The pressure within the formation directly above the sealing interval, either measured using monitoring wells or through multiple sealing levels on the injection well.

• Geochemical monitoring of USDWs may be required periodically (as agreed in the monitoring plan with the regulating authority) for groundwater quality and geochemical changes that may result from carbon dioxide or injection formation fluid movement into the overlying formations. Pressure in any overlying aquifer must be monitored. In addition, fluids should be sampled for:

  • pH
  • Temperature
  • Conductivity
  • Density
  • Total dissolved solids
  • Major ions
  • Tracers used
  • Dissolved gas concentrations (including DIC)

  Additional monitoring of other constituents may be identified by the owner or operator and/or the regulators. This may include but is not limited to any tracer being measured in the injectate, for example minor ions, select trace metals, stable isotopes of C in CO₂, CH₄ (if present) and DIC, $δ^{18}$O and $δ$D of H₂O, and inert tracer concentrations (e.g., noble gases).

• If using dissolved CO₂, water table levels and competing water usages should be monitored.

• Identification of any natural springs connected to the mineralization formation or USDWs within the storage site, with baseline and ongoing monitoring to ensure no CO₂ leaks (as agreed in the monitoring plan with the regulating authority). This should include:

  • pH
  • Temperature
  • Conductivity
  • Tracers used
  • Dissolved gas concentrations (including DIC)

• Ecosystem stress, where required by permit or certified geologist, which can be an early indicator for CO₂ leaks. Ideally, this should be monitored continuously with ad hoc random sampling to validate any anomalies. Continuous monitoring could either be done via site based phenocams or medium-to-high resolution [remote sensing] and compared to baseline images¹⁴.

• Surface displacement, which can inform on pressure changes or geomechanical impacts from CO₂ injection, and when compared to reserve models can indicate injection induced fracturing or changes in reservoir volume. Surface displacement should be monitored using one or more of the following techniques:

  • Satellite-based radar (SAR) or satellite interferometry (InSAR). Been previously used to measure small displacements of the ground surface (of up to 2–3 cm) that have been related to the injection of CO₂ at depth.
  • Surface- and subsurface-based tiltmeters.
  • GPS instruments.

Subsurface monitoring is required to demonstrate that solubility and mineralization trapping are occurring. This should be demonstrated using reservoir conditions, geochemical monitoring and modeling, and should quantify the percentage and rate or timescale of trapping and the amount of potential leaks.

• Continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) and periodic assessment of reservoir injectivity via a pressure fall-off test every two years. Direct measurement of fluid pressure may be achieved using transducers placed within monitoring wells in the injection zone, behind casing gauges, or through direct measurement of fluid depth through a perforation [B].

• Continuous measurements of pressure within the formation directly above the sealing interval, either measured using monitoring wells or through multiple sealing levels on the injection well.

• Geochemical monitoring locations, parameters, tools, spatial and temporal resolutions and detection limits should be defined in the monitoring plan as agreed by permitting authority or certified geologist. Tracer testing is a requirement, however the tracer used should be determined on a site specific basis. [A,C,E,G]. Tracers could include:

  • Reactive tracer testing:

    • Inherent tracers: Reservoir fluid sampling from the monitoring well(s) including but not limited to major and minor ions, dissolved gas concentrations, trace elements, pH, temperature, conductivity and DIC concentrations. DIC loss is expected along the flowpath from carbonate mineralization. This sampling should occur monthly unless the regulating permit requires more regular testing. Other inherent reactive tracers that could be used include $δ^{13}$C-CO₂/DIC, $δ^{44}$Ca and $δ$D and $δ^{18}$O of H₂O.
    • Spiked tracers: Reactive tracers (e.g., $^{14}$C) can also be added to the injected CO₂ stream. This should be performed following industry best practices. Spiked reactive tracers can lower uncertainties in any mass balance calculations, and may be required in systems where baseline DIC could not be determined, for example $^{14}$C concentrations within the fluids would be very low compared to the injected concentrations.
    • A comparison of the inherent or spiked pre- and post- injection can be used to quantify the amount of CO₂ dissolved and/or precipitated. For example, the amount of DIC loss compared to concentrations in the injected dissolved CO₂ can be used to quantify CO₂ mineralization².

  • Non-reactive tracer testing:

    • Non reactive tracers (e.g., noble gases) should be co-injected or measured if inherent with the CO₂ once The Project has reached stable operation or within the first two years of injection (whichever occurs earlier or is most appropriate for The Project, in line with findings from the Carbfix Project¹³) then sampled for in the monitoring well(s). Pulsed tracer injection should occur once a year after hydraulic connection with monitoring well/s is established.Tracer tests should be performed according to industry best practices.

    Reactive and non-reactive tracer data collected from monitoring wells should be combined in order to accurately quantify CO₂ trapping within the subsurface (e.g, mineralization) using mass balance equations^2,15:

  $$[i]_{min}=X\cdot[i]_{is}+(1-X)\cdot[i]_{bf}-[i]_{meas}$$
  

  (Equation 1)

  Where:

  • $i$ is the concentration of the reactive tracer (e.g., DIC, ¹⁴C).

  • $X$ is the fraction of injectate relative to formation fluid present in the sample (calculated using non reactive tracers).

  • $min$, $is$, $bf$ and $meas$ subscripts refer to the amount mineralized, in the injectate, background reservoir fluid and measured during monitoring, respectively.

    Reductions in the recovery of reactive tracers in monitoring wells relative to non-reactive tracers, coupled with concordant shifts in variables such as pH and fluid saturation states, indicates CO₂ is being mineralized in the reservoir.

  • Gas concentrations (including CO₂, CH₄ and H₂) where free gas is present

• At a minimum, all projects are required to monitor for seismic activity caused by operations using regional seismic data and report any seismic events of magnitude 2.7 or greater. An additional seismic monitoring program may be suggested at the discretion of the regulator or certified geologist in areas of increased seismic risk, where demonstrated that seismicity may have an impact on the formation and the long duration storage of CO₂. This shall include deeper wireline or cemented subsurface geophones for microseismic monitoring and could be combined with at/near ground level stations as part of an integrated strategy. Seismic monitoring can be used to determine the presence or absence of any induced micro-seismic activity associated with all wells and near any discontinuities, faults, or fractures in the subsurface, or any seismic activity in the area within the AOR of the injection facility and the area of the storage reservoir of magnitude 2.7 or greater [B].

• Physical evidence and signatures of mineralization from the reservoir can be collected using drill cores [G].

• If supercritical CO₂ is injected into the reservoir, additional subsurface monitoring must be considered [A]:

  • Indirect plume monitoring through reservoir imaging every 5 years (seismic, gravity and/or electrical methods) and comparison to baseline conditions and reservoir models is required. This will allow the presence or absence of elevated pressure within the injection zone and the extent of the CO₂ plume to be tracked.
  • Comparative hydrologic tests are recommended to identify changes in the reservoir hydraulic and/or storage characteristics attributed to injection⁵. This could include freshwater injection/recovery testing followed by a series of instantaneous pressurized slug/pulse withdrawal tests and wireline geophysical surveys. Results can be used within calibrated numerical models to quantify the amount of injected CO₂ that was mineralized.

Reservoir modeling must be performed, including pressure and fracture simulations, to assess CO₂ migration and behavior within the subsurface to confirm containment within the AOR. The model should be compared to data directly collected from the reservoir (e.g., pressure, temperature) and any other nearby relevant subsurface data (i.e., porosity and permeability of our injection horizon and confining/impermeable layer if applicable, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment CO₂ within targeted injection zone. It should also predict future performance which at a minimum should include: (i) percentage of CO₂ dissolving and mineralizing, (ii) comparison of monitoring data with modeled predictions. Reservoir models must be updated as operational data changes [A,B,C,E,F,G].

The final list of constituents to be monitored will be determined between the Project Proponent and regulating body or certified geologist on a project-specific basis using site-specific data from site characterization and injectate composition.

When the continuous gas detection system (Section 3.1.1.1) detects gas, a Triggered Gas Investigation must commence. This investigation comprises gas composition analysis and isotope analysis to determine the source and extent of detected gases. Both analyses are initiated concurrently,  isotope analysis is not contingent on results from composition analysis [C].

Monitoring of the wellhead pressure and composition of any gas recovered from well(s) or representative sampling locations where gas from the reservoir is detected must be completed on a monthly basis. Gas monitoring must include CO₂, CH₄, C₃H₈ and VOCs emissions from the well via species-specific gas monitors with a resolution of at least 0.01 vol%, or lab analysis, if sampled (e.g., gas chromatography on grab bag or equivalent samples). When concentrations above background atmospheric levels are detected, a sample must be taken to establish the chemical composition of the displaced gases (including CO₂, CH₄, C₃H₈, N₂, O₂ and VOCs). Results must be compared to baseline values obtained prior to CO₂ injection. Wellhead pressure should be monitored continuously, and wellhead gas sampling should be monthly [B,C].

The Project Proponent/Operator must prepare an emergency response plan which outlines corrective actions which will be taken in case of CO₂ leaks. The plan must be submitted and approved by the component permitting authority. If any CO₂ leaks are detected from the target reservoir or there are significant irregularities from the used model(s), the Project Proponent/Operators must undertake corrective measures as set out in their emergency response plan and approved by the competent authority.

For CO₂ leaks, the Project Proponent is required to:

• Halt injection while an assessment is conducted
• Determine if the loss of containment can be repaired prior to injection beginning again
• Quantify the amount of CO₂ lost

For a loss of conformance with models, the Project Proponent is required to:

• Halt injection while they identify the cause of this loss
• Modify operations to increase dissolution/mineralization
• Pause injection and monitor for dissolution/mineralization (this will likely be the case if solubility trapping is slower than expected), and /or
• Update their monitoring plan and approve permitting authority or certified geologist

Re-evaluations of the CO₂ plume extent must also be implemented when warranted based on observational or quantitative changes of the monitoring parameters of the storage reservoir, including but not limited to:

• Observed and unexpected migration of the CO₂ plume which suggests potential movement of CO₂ outside the intended formation
• CO₂ migration into a zone above the storage complex
• CO₂ plume or elevated pressure extend beyond analytical model expectation because any of the following has occurred:
  • An seismic event of magnitude 2.7¹⁶ or greater within the AOR
  • New site characterization data change the model inputs to such an extent that the predicted CO₂ fluid and/or pressure plume extends vertically or horizontally beyond what was originally predicted

Further information on the risk and attribution of reversals Section 4.0 and Section 4.1.

The aim of this post-injection monitoring and the closure requirements in Section 8.0 is to put in place scientific and/or operational monitoring practices in order to prove beyond reasonable doubt that CO₂ storage will be durable on geologic timescales. Addressing potential risks to durability is important for ensuring robust and diligent carbon dioxide removals. The Project Proponent must follow any post-injection and site decommissioning requirements of the permit for the specified Project. Post-injection is defined as monitoring between the end of injection and plugging of the wells. Once injection has ceased (this is defined as closure in the EU) the site must undergo post-injection monitoring. Once it is demonstrated that the injectate plume (which has not yet been mineralized) is stable (i.e., no longer migrating) within the storage reservoir and unable to impact on the USDWs, wells can be plugged and the site decommissioned (this is defined as the closure point in the US). Within the EU, the Project Proponent must transfer the site to the national/local authorities where monitoring will continue. Within the USA, additional post-closure monitoring may be discontinued if allowed under the applicable UIC permit. If operating in another region, the Project Proponent must follow guidance from the regulating authority.

Post-injection monitoring should apply the same monitoring strategy as implemented during injection and operation, with a focus on methods tailored to address the anticipated system changes and risks that may occur. Post-injection monitoring must be carried out in accordance with the local permitting regime (for approved permits) or the certified monitoring plan (for other jurisdictions). This monitoring, therefore, must focus on using reservoir modeling alongside direct measurements the injection well of formation fluid temperature, tracer concentration, pH and conductivity, reservoir pressure and pressure in the zone immediately above the sealing interval to trace plume migration and the pressure front to confirm mineralization and lack of plume migration. If supercritical CO₂ was injected, indirect imaging may also be used. If applicable and if the pressure front migrates in a new direction, the installation of additional monitoring wells may be required. Seismic monitoring using regional seismic data must continue, and events of magnitude 2.7 or greater must be reported. Corrosion monitoring and external mechanical integrity testing must be conducted annually for the first three years after injection. Annulus pressure must initially be measured monthly. A pressure fall-off test must initially be conducted every two years. It is recommended that USDWs and any natural springs present be monitored to identify and address any leaks that arise. Any measured parameters should be compared to modeled predictions to help refine the model or identify possible risks. The frequency of post-injection monitoring may be reduced, determined by specific, risk-based, quantitative criteria detailed as part of the regulating permit or approved monitoring plan. Such criteria could include the reservoir pressure reaching a certain level relative to pre-injection conditions or steady or favorable trends (towards mineralization and dissolution) in observed geochemical monitoring results over a predefined period, and agreement with model predictions.

Periodic assessment (15 years (USA) or 20 years (EU) or equivalent, but likely sooner if mineralization can be proved) must be completed to demonstrate mineralization, dissolution and plume stabilization or a trend towards, this time period may change at the discretion of the regulating body. Re-assessments will be carried out until permanent containment of the stored CO₂ in order to eliminate the risk of migration or release of CO₂ from the storage formation to the atmosphere or USDWs. The Project Proponent will actively explore emerging technologies for measuring plume stabilization. The plume stabilization assessment must be conducted in one of the following ways:

• Geochemical and/or tracer to demonstrate CO₂ mineralization, dissolution and lack of any vertical migration of tracers in the CO₂ plume to any areas outside of the authorized injection zone or outside of the predicted lateral extent within the AOR.
• Core studies to verify mineralization within the reservoir^{17, 18}.
• Utilize predictive modeling based on monitoring data collected during post-injection monitoring to demonstrate that CO₂ has been mineralized and/or dissolved, and lack of CO₂ migration in the formation that would present risk to water sources in the AOR. If supercritical CO₂ was injected the model must also investigate plume stability to ensure this.
  • Modeling must be validated by comparison to historical monitoring data of subsurface pressure and operational/post-injection monitoring.
  • Models must utilize site specific geochemistry, CO₂ characteristics from analyses required in Section 3.1.3 of this Module.
  • Models must assess the behavior and trapping of CO₂ for 50 years and demonstrate that there is no risk of migration beyond the AOR and it will not impact drinking water sources nor cause other environmental harms.
  • Comparison of model to predictions made at the time a site decommissioning plan was approved.
• For supercritical CO₂ injection, geophysical monitoring of the CO₂ plume may be performed to demonstrate limited change since the cessation of injection.
• Or new methods as outlined in subsequent Module versions and as measurement and monitoring technologies advance.

The timeframe for post injection monitoring should be aligned with regulatory guidance and based on site specific operation and monitoring data, for example where CO₂ mineralization (and plume stabilization for supercritical injection) is not demonstrated. If the regulating authority does not have guidance on the minimum timeframe, this is set at a minimum of 50 years, unless mineralization can be proven.The length of ongoing monitoring will be subject to change given subsequent reanalyses.

If CO₂ mineralization (and plume stabilization for supercritical injection) can be demonstrated by the above methods, and is independently reviewed and certified by a registered Professional Geologist (i.e. Chartered Geologist or equivalent), the CO₂ will be considered stabilized and the site decommissioned following requirements in Section 8.0.

The reversal risk shall be determined on a project by project basis. There should be no reversals unless there is a loss of well integrity or migration outside of the storage complex, and this technology does not yet have a documented history of reversals. Based on present levels of scientific knowledge, ++Projects applicable to this Module are typically categorized as having a Very Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire (also found in the relevant Protocol). This results in a 1% buffer pool for Projects using this Storage Module. This reversal risk will be reassessed at the renewal of the Crediting Period++, or when new scientific research and knowledge are produced.

In instances where reversals are determined to be a result of negligence by the storage operator, Project Crediting may be ceased. Reversals will be accounted for by Projects and the Isometric Registry as detailed in the Reversal and Buffer Pool Section of the Isometric Standard.

When a reversal is detected and quantified, there are multiple considerations that will be taken into account to attribute the reversal to whatever has been injected in the targeted reservoir.

1. If the Project Proponent was the only entity injecting into a given reservoir, the Project Proponent will take on 100% of the reversal.
2. If the Project Proponent was one of multiple entities injecting into that reservoir, the Project Proponent will be allocated a percentage of the reversed CO₂ proportional to the mass of injected material. For example:

• A reservoir has a total of 200t of material injected at the time when the reversal is detected (this information must be provided by the Operator).
  • The Project Proponent has injected 50t of material in that reservoir.
  • The amount of reversed CO₂ has been quantified to be 10t.
  • The Project Proponent must compensate for 25% (50/200) of 10t CO₂ = 2.5t of CO₂.

In instances where reversals are determined to be a result of negligence by the Operator or Project Proponent, Project Crediting may be ceased.

$CO_2e_{Storage,\ RP}$ represents the amount of CO₂ present in the CO₂-containing injectant that is injected and stored in the geologic or engineered storage formation in a given Reporting Period ($RP$). This is the gross mass stored and does not account for reversals of storage from the storage formation.

This can be calculated by using the mass injected and the average concentration of CO₂ in the injectant over a given time period, summed across the whole $RP$:

$$CO_2e_{Storage,\ RP} = \sum_{t=1}^{T}  C_{mean, inj,t} \cdot m_{inj,t}$$

(Equation 2)

Where:

• $C_{mean,inj,t}$ = the measured average concentration as weight percent (%wt) of CO₂ within the injectate, or measured C content divided by the fraction of C in CO₂ for dissolved CO₂.
• $m_{inj,t}$ = the mass of CO₂-containing injectant (in tonnes) injected during period $t$.
• $t$ = the time index, ranging from 1 to $T$.
• $T$ = $RP/Δt$, the number of time units in the Reporting Period, $RP$.
• $Δt$ = the time interval the average is taken over.

The mass of CO₂-containing injectant, $m_{inj,t}$, may either be directly measured using a mass flow meter, or may be indirectly measured by combining suitable volume and density measurements. In the latter case, the mass of injectant is calculated as:

$$m_{inj,t} = V_{inj,t} \cdot \rho_{inj,t}$$

(Equation 3)

Where:

• $V_{inj,t}$ = the volume of CO₂-containing injectant injected during period $t$.
• $\rho_{inj,t}$ = the density of CO₂-containing injectant injected during period $t$.

The density of the injectant may be measured either using a calibrated density meter, or may be indirectly measured by combining suitable pressure and temperature measurements. In the latter case, the density should be determined as a function of the pressure and temperature measurements by application of a suitable gas-phase equation of state model. Supporting information, including appropriate published scientific literature and/or internal empirical evidence, demonstrating the accuracy of the applied equation of state must be provided at the point of third party Project verification.

Calculation of $CO_2e_{Storage,\ RP}$ requires two primary measurements

• ${C_{inj}}$: %wt of CO₂ in the CO₂ injection stream or %wt C within a carbonate solution divided by C content in CO₂ (44/12); and
• $m_{inj}$: total mass of injectant, in tonnes.

The concentration of CO₂ in the dissolved or supercritical CO₂ stream must be:

• Measured immediately upstream from the point of injection; and
  • Where CO₂ streams from multiple Projects are injected into a single storage location, total CO₂ mass input from The Project and of the total CO₂ stream to which it is injected may be measured at the location of transfer from the capture facility into the combined stream. The weight fraction of CO₂ determined at this point may be used to calculate the CO₂ injected as measured immediately upstream from the injection point.
• Measured either continuously or periodically if concentrations are proven to be consistent
  • If measuring CO₂ concentrations continuously, a continuous inline analyzer for CO₂ concentration, such as NDIR, TDL, or similar, which satisfies the below requirements, should be used:
    • Must have an accuracy of 2% of full scale or better;
    • Recorded at a frequency of 1-minute intervals at minimum;
    • Must be calibrated in accordance with and at a frequency which meets or exceeds manufacturer calibration requirements, but which in any case must be no less than annual;
    • Calibration gases must be traceable to national standards and a certificate of analysis indicating so; and
    • Raw data must be made available upon request.
  • If measuring CO₂ concentrations periodically:
    • Samples must be intially taken frequently to ensure CO₂ concentration at an appropriate statistical significance.
    • One statistical signficance has been reached samples may be taken quarterly unless otherwise stated in the permit.

The mass of injectant ($m_{inj}$) is measured via use of a calibrated mass flow meter or volumetric flow meter and density measurements over a defined time interval ($Δt$). Preference is for high-accuracy flow meters such as coriolis or thermal mass flow meters, although other metering solutions are allowable. Flow metering must meet the following requirements:

• Provided with a factory calibration for the specific gas composition range expected;
• Meter accuracy specification of 2% full scale;
• Must be calibrated in accordance with and at a frequency which meets or exceeds manufacturer calibration requirements, but which in any case must be no less than annual;
• Calibration traceable to national standards;
• Meters are selected and installed for the expected and observed operating range of the injected stream;
• Meters are installed in accordance with manufacture installation guidelines, including, for example, minimum distances up or downstream of piping disturbances required to ensure accurate flow measurement; and
• Raw data must be made available upon request

In general, the Project Proponent must identify, highlight, and explain any data gaps or missing calibration data, if any occur. The Project Proponent must notify Isometric and the VVB when data gaps or missing calibration data occur and must clearly explain the approach taken and document the missing data within the GHG statement.

For those parameters where frequent, sub-hourly measurements are required (notably CO₂ concentration measurements in the CO₂ stream, and the measurement of mass of CO₂ injected), the Project Proponent must adhere to the following procedure for handling missing data.

Where there are data gaps in measurement of the relevant parameter of up to 30 minutes, the Project Proponent may claim using an average quantity, based on the measurements proceeding and following the data gap.

Where there are such data gaps of longer than 30 minutes, the Project Proponent may apply this approach for up to a 30 minute period within the duration of the data gap, but no more than this. For the remainder of the period of the data gap, i.e. in excess of 30 minutes, no carbon dioxide removal may be claimed, due to a lack of data. In addition, data gaps must account for less than 5% of the data used for the removal calculation within a given Reporting Period, any missing data above this is also not creditable.

Where a calibration is missed, one must be completed as soon as this is noticed. For data collected between when the calibration was required and when it actually took place, a conservative estimate should be used agreed between the VVB, Project Proponent, and Isometric.

The Project Proponent must maintain the following records as evidence of gross CO₂ storage in injected CO₂ or CO₂-containing injectant:

• Raw data provided via CO₂ stream meters (mass and concentration measurements) for the $RP$;
• Analytical results for each supporting injectant analysis specified in Section 5.0;
• Records of any other mass measurements, such as weigh scale tickets;
• Calibration records for all measurement equipment, including, but not limited to:
  • Flow meters;
  • CO₂ analyzers, and
  • Weigh scales;
• Manufacturer operating manuals indicating required calibration procedures and frequency, as well as maintenance procedures and frequency for all measurement equipment;
• Laboratory accreditation records;
• Laboratory analytical reports, including evidence of quality assurance and quality control (QA/QC) activities;
• Documentation of any spills during injection operations and estimates of quantity released; and
• Reports of any instrument failures or down time.

Records of all analyses and injections must be maintained by the storage facility or Project Proponent and provided for verification purposes for a minimum of five years after the end of the monitoring period.

Type: Counterfactual

The counterfactual for eligible Projects is considered to be zero.

$CO_{2}e_{Emissions}$ is the total greenhouse gas emissions associated with a given Reporting Period, $RP$.

Equations and emissions calculation requirements for $CO_{2}e_{Emissions}$, including considerations for monitoring activities, are set out in the relevant Protocol and are not repeated in this Module.

In order to decommission a site, the Project Proponent must prove beyond reasonable doubt that injected CO₂ will cause no harm to USDWs and stay within the AOR and thus CO₂ storage will be durable for the expected > 100,000 year timescales. The Project Proponent must ensure that all the regulators permit requirements associated with planning for, proceeding with and monitoring of well or site decommissioning are adhered to and documented.

Decommissioning of the site must follow local statutory requirements. If supercritical CO₂ was injected, the Project Proponent, during decommissioning, must ensure flushing of all wells with a buffer fluid, determine bottom hole reservoir pressure, and perform a final external mechanical integrity test to ensure that plugging materials and procedures are selected correctly. All injection and monitoring wells should then be plugged appropriately using CO₂ resistant cement and to the regulators requirements. For dissolved injections, well cementing is not required as part of this Module as when solubility/dissolution trapping has been confirmed the risk of release from the geologic reservoir is negligible.

A site report (providing information on the operation, monitoring & modeling and closure procedures) should be created by the Project Proponent and submitted to regulatory bodies and carbon storage agreements with pore space owners will ensure activity in the storage site is prohibited for perpetuity following CO₂ injection, ensuring that even if any supercritical CO₂ does not dissolve or precipitate, it will not be subject to pressure disturbances (i.e, injection or production activities) in the storage reservoir and land owners will be aware. It is also recommended that the Project Proponent notifies other Stakeholders, such as nearby drinking water utilities and agencies with primacy for drinking water regulations. A copy of the site decommissioning plan should also be retained by the Project Proponent for a minimum of 10 years (or longer if required by the regulator) following site decommissioning.

Within the US, site decommissioning does not eliminate any potential responsibility or liability of the owner or operator under other provisions of law. For example, the Project Proponent may still hold some responsibility for any remedial action deemed necessary for USDW endangerment caused by the injection operation.

Within the EU, the site is transferred from the Project Proponent to a competent authority (i.e., national or local authorities) once mineralization, dissolution and plume stability has been established and the site decommissioned. After the transfer of responsibility, the competent authority will continue with monitoring at a reduced rate which still allows for identification of CO₂ leaks or significant irregularities. This will be intensified if CO₂ leaks or significant irregularities are identified.

All records associated with the characterization, design, construction, injection operation, monitoring, and site closure must be developed, reported in the project design document, to the VVB and to proper authorities as required by the permit.

Records of laboratory analyses and relevant permit limitations to demonstrate compliance must be maintained in accordance with the well permit and available for review at any point during the Crediting Period or post closure. Where not required by the permit, records of all analyses and injections must be maintained by the storage facility or Project Proponent and provided for verification purposes for a minimum of five years after the end of the monitoring period.

All closure and post-closure monitoring records must be maintained by the Project Proponent for a minimum of 10 years after closure. These records must be available to be consulted by interested parties for future clarifications if needed.

Isometric would like to thank Chris Holdsworth (University of Edinburgh as of the time of contributing) for contributing to this Module.

Isometric would like to thank James Campbell, Ph.D. (Heriot-Watt University) for reviewing this Module.

Rebecca Tyne, Ph.D.

Nicholas Ashmore, Ph.D.

This appendix details how the Project Proponent must monitor, document and report all metrics identified within this Module to demonstrate the durability of CO₂ removal. Following this guidance will ensure the Project Proponent measures and confirms CO₂ removed and long-term storage compliance, and will enable quantification of the emissions removal resulting from The Project activity during The Project Crediting Period, prior to each Verification.

This methodology utilizes a comprehensive monitoring and documentation framework that captures the GHG impact in each stage of a Project. Monitoring and detailed accounting practices must be conducted throughout to ensure the continuous integrity of the carbon dioxide removals and Crediting.

The Project Proponent must develop and apply a monitoring plan according to ISO 14064-2 principles of transparency and accuracy that allows the quantification and proof of GHG emissions removals.

Table A1 Pre-Injection Monitoring Requirements

Table A2 Operational Monitoring Requirements

Table A3 Post-Injection Monitoring Requirements

Here is a list of permits which are currently approved by Isometric. These permits are in regime with strong track records of safe CO₂ injection and publicly available robust regulations. As new regulatory regimes are developed, this list will be updated.

Current approved permits:

• U.S. EPA Underground Injection Control (UIC) Class VI¹⁹
• EU directive 2009/31/EC (including subsequent guidance documents)²⁰
• Norway licence for exploitation of a subsea reservoir for storage of CO₂ ²¹
• North Sea Transition Authority, Regulation 2010 (SI 2010/2221) ²²
• Alberta Energy Regulator (AER) Directive 064 ^{23 24}

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4. McGrail, B. P., Schaef, H. T., Spane, F. A., Horner, J. A., Owen, A. T., Cliff, J. B., Qafoku, O., Thompson, C.J., & Sullivan, E. C. (2017). Wallula Basalt Pilot Demonstration Project: Post-injection Results and Conclusions. Energy Procedia, 114, 5783–5790. https://doi.org/10.1016/j.egypro.2017.03.1716 ↩

5. White, S. K., Spane, F. A., Schaef, H. T., Miller, Q. R. S., White, M. D., Horner, J. A., & McGrail, B. P.(2020). Quantification of CO2 Mineralization at the Wallula Basalt Pilot Project. Environmental Science& Technology, 54(22), 14609–14616. https://doi.org/10.1021/acs.est.0c05142 ↩ ↩²

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7. Tyne, R. L., Barry, P. H., Lawson, M., Byrne, D. J., Warr, O., Xie, H., Hillegonds, D. J., Formolo, M., Summers, Z. M., Skinner, B., Eiler, J. M., & Ballentine, C. J. (2021). Rapid microbial methanogenesisduring CO2 storage in hydrocarbon reservoirs. Nature, 600(7890), 670–674. https://doi.org/10.1038/s41586-021-04153-3 ↩ ↩²

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9. Zakharova, N. V., Goldberg, D. S., Sullivan, E. C., Herron, M. M., & Grau, J. A. (2012). Petrophysical andgeochemical properties of Columbia River flood basalt: Implications for carbon sequestration. Geochemistry, Geophysics, Geosystems, 13(11), Q11001. https://doi.org/10.1029/2012GC004305 ↩

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12. Bubble Point Pressure is the pressure at which the first bubble of gas (including CO₂) forms when a liquid is depressurised. ↩

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16. Code Regs., tit. 14, § 1724.14, “Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations,” (2017). Not accesible in the EU, Copy available on request. ↩

17. McGrail, B. P., Schaef, H. T., Spane, F. A., Horner, J. A., Owen, A. T., Cliff, J. B., Qafoku, O., Thompson, C.J., & Sullivan, E. C. (2017). Wallula Basalt Pilot Demonstration Project: Post-injection Results and Conclusions. Energy Procedia, 114, 5783–5790. https://doi.org/10.1016/j.egypro.2017.03.1716 ↩

18. Callow, B., Falcon-Suarez, I., Ahmed, S., & Matter, J. (2018). Assessing the carbon sequestration potential ofbasalt using X-ray micro-CT and rock mechanics. International Journal of Greenhouse Gas Control, 70,146–156. https://doi.org/10.1016/j.ijggc.2017.12.008 ↩

19. United States EPA. (2013). Geological Sequestration of Carbon Dioxide: Underground Injection Control (UIC) Program Class VI Well Testing and Monitoring Guidance. https://www.epa.gov/sites/default/files/2015-07/documents/epa816r13001.pdf ↩

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21. Norwegian Offshore Directorate. (2017). Regulations relating to exploitation of subsea reservoirs on the continental shelf for storage of CO₂ and relating to transportation of CO₂ on the continental shelf. https://www.sodir.no/en/regulations/regulations/exploitation-of-subsea-reservoirs-on-the-continental-shelf-for-storage-of-and-transportation-of-co/ ↩

22. UK Government. (2010). The Storage of Carbon Dioxide (Licensing etc.) Regulations 2010. https://www.legislation.gov.uk/uksi/2010/2221/contents/made ↩

23. Alberta Energy Regulator. (2023). Directive 065: Resources Applications for Oil and Gas Reservoirs. https://static.aer.ca/prd/documents/directives/Directive065.pdf ↩

24. Alberta Energy Regulator. (2022). Directive 087: Well Integrity Management. https://static.aer.ca/prd/documents/directives/directive-087.pdf ↩