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

2.2 Evidence Reporting

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 (Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.) within 30 days of submission to the permitting authority, or upon request.

For monitoring requirements not covered under the Approved Permit, the Project Proponent (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) remains responsible for collecting and reporting all required data directly to Isometric and the VVB (Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.) 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 (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) must notify Isometric and the VVB (Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.) immediately of any changes which may impact monitoring requirements. Monitoring plans will be subject to reevaluation following such changes.

2.3 Site Characterization

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 (MgCa²⁺, CaMg²⁺, 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.
• Fluid saturation of the storage reservoir.
• 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 (if gaseous CO2 is not injected) 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 (A collection of Removal or Reduction processes that have mechanisms in common.) 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.
• ReservoirBubble characteristicspoint pressure must also be characterisedcalculated, using appropriate geochemical tools (e.g., PHREEQC software version 3), thermodynamic databases and equations of state (e.g., Peng-Robinson). ThisIt includesmust butinclude isconsideration notof limited tothe:
  • ReservoirMass temperature
  • Reservoirflow pressure
  • Formation (reservoir) fluid pH
  • Formation (reservoir) fluid denisty
  • Formation (reservoir) fluid conductivity
  • Compositionrate of the formationCO₂ (reservoir)stream fluid, in particularentering the DICinjection concentrationwell.
  • Mass andflow rate of anythe tracerswater usedstream 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.

PermitsThe may also ensure safety of USDWs. In order to ensure this, the Project Proponent is(The requiredorganization tothat completedevelops and/or has overall legal ownership or control of a Removal or Reduction Project.) must conduct a baseline (A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.) characterization of the systemAOR (The area surrounding an injection well described according to the criteria set forth in the U.S. Code of Federal Regulations § 40 CFR.146.06, which, in some cases, such as Class II wells, the project area plus a circumscribing area the width of which is either 1⁄4 of a mile or a number calculated according to the criteria set forth in § 146.06.) 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 (The period of time over which a Project Design Document is valid, and over which Removals or Reductions may be Verified, resulting in Issued Credits.) 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.

2.4 Site Visits

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.

2.5 Well Construction Requirements

• 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

3.0 Monitoring

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.

3.1 Injection and Operational Monitoring Requirements

3.1.1 Injection and Injectant Operation & Monitoring

• 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 3.45.3).
  • 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 [BD, E]:
  • pH and temperature
  • Viscosity
  • CO₂ concentration (i.e., wt% CO₂, C content). More information on these measurements can be found in Section 3.45.2.
  • 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.
  • IfMajor ions within dissolved CO₂ is being injected, major ions should, and [math: δ^{18}]O, [math: δ]D could, also be measuredstreams.

Additional measurements may include:

• δ¹³C of the CO₂/DIC (if dissolved).
• Minor ions within dissolved CO₂ streams.
• [math: δ^{18}]O, [math: 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.

3.1.1.1 Continuous Gas Monitoring

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, at a minimum, 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 systemsalarms indicate elevated CO2, CH4, H2 or H2S levels in headspace. Ifare activated theat operatorany 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 theIsometric. validationWhere a Triggered Gas Investigation (Section 3.1.3.3) is already active, individual alarm events must be logged and verificationreported bodybut (VVB)do not require a separate investigation unless they indicate a materially different or escalating condition [C].

3.1.2 System Integrity Monitoring

• ACorrosion demonstrationmonitoring ofmust internal mechanical integritybe performed and reported annually, unless otherwise specified in the permitquarterly. 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 [BA, 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 leakagepathways pathwayfor leaks [BA, D].
• A pressure fall-off test, every 2 years [BA, D].
• Continuous monitoring of pressure within the wellbore annulus [A, D].

3.1.3 Migration, Trapping and Storage Reversal Monitoring

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.

3.1.3.1 Near surface monitoring

ThisNear issurface 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,B]. This includes monitoring of:

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

• Surface gas, incluidng including CO₂, H₂ and CH₄, concentrations and fluxes to identify large point-source leaks every two years. 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) (LiDAR is a remote sensing technology that uses laser pulses to create highly accurate three-dimensional maps of forest structure, enabling measurements of tree height, canopy density, and biomass.)
  • 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 [math: 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 ismay be required periodically (as agreed in the monitoring plan with the regulating authority) for ground watergroundwater 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 and minor 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, [math: δ^{18}]O and [math: 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 leakageleaks (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, (ifwhere required by thepermit 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 (A remote sensing technology which uses radio waves to create images of the earth’s surface.)) 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 (A satellite-based navigation system.) instruments.

3.1.3.2 Subsurface monitoringMonitoring

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 leakage [A,B]leaks.

• Continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) and periodic (6 monthly) assessment of reservoir injectivity via a pressure fall-off test every two years. MeasurementDirect measurement of in-situ fluid pressure that 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 regulatingtracer body. Thisused should include but not be limiteddetermined toon 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 [math: δ^{13}]C-CO₂/DIC, [math: δ^{44}]Ca and [math: δ]D and [math: δ^{18}]O of H₂O.
    • Spiked tracers: Reactive tracers (e.g., [math: ^{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 [math: ^{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 theThe Project has reached stable operation or within the first two years of injection (whichever occurs earlier or is most appropriate for theThe 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:

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

(Equation 1)

Where:

• [math: i] is the concentration of the reactive tracer (e.g., DIC, ¹⁴C).
• [math: X] is the fraction of injectate relative to formation fluid present in the sample (calculated using non reactive tracers).

• [math: min], [math: is], [math: bf] and [math: 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

3.1.3.3 Reservoir Modeling

3.1.3.4 Triggered Gas Investigation

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, leakage

IfCH₄, C₃H₈, N₂, O₂ and VOCs). Results must be compared to baseline (A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.) values obtained prior to CO₂ leakageinjection. isWellhead pressure should be monitored continuously, and wellhead gas sampling should be monthly [B,C].

3.1.3.5 CO₂ Leaks

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 targetedtarget reservoir or there are significant irregularities from the used model(s), the Project Proponent/Operators will need tomust undertake corrective measures as set out in their monitoringemergency response plan submitted 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 withpermitting the UIC directorauthority or equivalent

Forcertified CO2 leakage, 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 lostgeologist

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 34.30 and Section 3.34.1.

3.2 Post Injection Monitoring

It is recommended that for postPost-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 from the injection well/monitoring wellof 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. USDWs should also be monitored to identify and address any CO2 leakage pathways that arise. Mechanical integrity of monitoring wells and the injection well should occur annually for the first three years after injection ceasing and every five years until site decommissioning, to ensure the wells do not become a leakage pathway. 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 48.0.

3

4.30 Risk of Reversal

BasedThe reversal risk shall be determined on present levels of scientific knowledge, Projects applicable to this Module are categorized as having a Veryproject Lowby Riskproject Level of Reversal according to the Isometric Standard Risk Assessment Questionnairebasis. This is because thereThere should be no reversals unless there is a loss of caprockwell integrity or wellmigration integrityoutside of the storage complex, and this technology does not yet have a documented history of reversals. ThereBased ison present levels of scientific knowledge, ++Projects applicable however,to this Module are typically categorized as having a riskVery Low Risk Level of methaneReversal productionaccording withinto the Isometric Standard Risk Assessment Questionnaire (also found in the reservoir,relevant based on current literature, but this risk is very small19Protocol). AsThis results in a result, a 21%  buffer pool (A common and recognized insurance mechanism among Registries allowing Credits to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.) for willProjects beusing setthis asideStorage as a precautionModule. This reversal risk will be reassessed every 5 years, aligning withat the renewal of the Crediting Period (The period of time over which a Project Design Document is valid, and over which Removals or Reductions may be Verified, resulting in Issued Credits.)++, 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 (A database that holds information on Verified Removals and Reductions based on Protocols. Registries Issue Credits, and track their ownership and Retirement.) as detailed in the Reversal and Buffer Pool Section 5.6 of the Isometric Standard.

3.3

4.1 Attribution of reversals

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 CO₂₂ 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 CO₂₂ has been quantified to be 10t.
• The Project Proponent must compensate for 25% (50/200) of 10t CO₂₂ = 2.5t of CO₂₂.

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

3

5.40 Calculation of CO₂e_{StoredStorage}

[math: CO_2e_{StoredStorage,\ 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 ([math: 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 [math: RP]:

[math: CO_2e_{StoredStorage,\ RP} = \sum_{t=1}^{T}  C_{mean, inj,t} \cdot m_{inj,t}]

(Equation 2)

Where:

• [math: 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.
• [math: m_{inj,t}] = the mass of CO₂-containing injectant (in tonnes) injected during period [math: t].
• [math: t] = the time index, ranging from 1 to [math: T].
• [math: T] = [math: RP/Δt], the number of time units in the Reporting Period, [math: RP].
• [math: Δt] = the time interval the average is taken over.

The mass of CO2CO₂-containing injectant, [math: 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:

[math: m_{inj,t} = V_{inj,t} \cdot \rho_{inj,t} ]

(Equation 3)

Where:

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

3.4

5.1 Measurement - CO₂e_{StoredStorage}

Calculation of [math: CO_2e_{StoredStorage,\ RP}] requires two primary measurements

• [math: {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
• [math: m_{inj}]: total mass of injectant, in tonnes.

3.4

5.2 CO₂ Concentration Measurements in CO₂ Streams

3.4

5.3 Measurement of Mass of CO₂ Injected

The mass of injectant ([math: m_{inj}]) is measured via use of a calibrated mass flow meter or volumetric flow meter and density measurements over a defined time interval ([math: 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

3.4

5.4 Procedure for handlingHandling missingMissing data

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 (A document submitted alongside Claimed Removals and/or Reductions that details the calculations associated with a Removal or Reduction, including the Project's emissions, Removals, Reductions and Leakages, presented together in net metric tonnes of CO₂e per Removal or Reduction.).

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 (Purposefully erring on the side of caution under conditions of Uncertainty by choosing input parameter values that will result in a lower net CO₂ Removal or GHG Reduction than if using the median input values. This is done to increase the likelihood that a given Removal or Reduction calculation is an underestimation rather than an overestimation.) estimate should be used agreed between the VVB, Project Proponent, and Isometric.

3.4

5.5 Required Records and Documentation - CO₂e_{StoredStorage}

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

• Raw data provided via CO₂ stream meters (mass and concentration measurements) for the [math: RP];
• Analytical results for each supporting gaseous injectant analysis specified in Section 35.40;
• 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 injectionstorage facility or Project Proponent and provided for verification (A process for evaluating and confirming the net Removals and Reductions for a Project, using data and information collected from the Project and assessing conformity with the criteria set forth in the Isometric Standard and the Protocol by which it is governed. Verification must be completed by an Isometric approved third-party (VVB).) purposes for a minimum of five years after the end of the monitoring period (A period during which a Project has any obligations, under the selected Protocol, to submit ongoing Monitoring data to Isometric and the VVB.).

3

6.50 Calculation of CO₂e_{Counterfactual}

Type: Counterfactual

The counterfactual for eligible Projects is considered to be zero.

3

7.60 Calculation of CO₂e_Emissions

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

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

48.0 Closure Requirements

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.

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 leakagesleaks or significant irregularities. This will be intensified if CO₂ leakagesleaks or significant irregularities are identified.

4

9.10 Recordkeeping

All records associated with the characterization, design, construction, injection operation, monitoring, and site closure must be developed, submittedreported in the project design document (The document, written by a Project Proponent, which records key characteristics of a Project and which forms the basis for Project Validation and evaluation in accordance with the relevant Certified Protocol. (Also known as “PDD”).), to the VVB and to proper authorities as required by the regulatingpermit.

Records of laboratory analyses and relevant permit. All recordslimitations 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 10five years after the injectionend 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.

510.0 Acknowledgements

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.

611.0 Contributors

Rebecca Tyne, Ph.D.

Nicholas Ashmore, Ph.D.

12.0 Definitions and Acronyms

Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.

The amount of time carbon removed from the atmosphere by an intervention – for example, a CDR project – is expected to reside in a given Reservoir, taking into account both physical risks and socioeconomic constructs (such as contracts) to protect the Reservoir in question.

Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.

Describes the addition of carbon dioxide removed from the atmosphere to a reservoir, which serves as its ultimate destination. This is also referred to as “sequestration”.

A location where carbon is stored. This can be via physical barriers (such as geological formations) or through partitioning based on chemical or biological processes (such as mineralization or photosynthesis).

A calculation, series of calculations or simulations that use input variables in order to generate values for variables of interest that are not directly measured.

An aquifer, or a portion of one, which supplies or has the possibility to supply any public water supply system, or drinking water for human consumption.

The escapeterm ofused CO₂to describe greenhouse gas emissions to the atmosphere after it has been stored, and afteras a Creditresult has been Issued. A Reversal is classified as avoidable if aof Project Proponent has influence or control over it and it likely could have been averted through application of reasonable risk mitigation measures. Any other Reversals will be classified as unavoidableactivities.

A body of similar rock type (e.g. color, grain size, mineral composition, texture) and a particular location in the stratigraphic column (vertical rock layers). Formations are large enough to be mappable on Earth's surface or traceable in the subsurface.

An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.

The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.

The escape of CO₂ to the atmosphere after it has been stored, and after a Credit has been Issued. A Reversal is classified as avoidable if a Project Proponent has influence or control over it and it likely could have been averted through application of reasonable risk mitigation measures. Any other Reversals will be classified as unavoidable.

A United States Government agency that protects human health and the environment.

EnhancedA hydrocarbondocument recoverythat (EHR)describes ishow ato tertiaryquantitatively hydrocarbon production technique or process whereassess the physicochemicalnet (physical and chemical) properties of the rock and/or the fluids are changed to enhance the recovery of hydrocarbon, typically by altering the chemical, biochemical, density, miscibility, interfacial tension (IFT)/surface tension (ST), viscosity and thermal properties to enable additional hydrocarbon production (SPE, 2023). EHR+ is the specific useamount of CO₂ injectionremoved forby EHRa whereprocess. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the CO₂Carbon remainsFluxes storedinvolved in the geologicCDR formationprocess. permanentlyA (IEA,Protocol 2015)measures the full carbon impact of a process against the Baseline of it not occurring.

The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.

Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.

The area surrounding an injection well described according to the criteria set forth in the U.S. Code of Federal Regulations § 40 CFR.146.06, which, in some cases, such as Class II wells, the project area plus a circumscribing area the width of which is either 1⁄4 of a mile or a number calculated according to the criteria set forth in § 146.06.

A systematic and independent process for evaluating the reasonableness of the assumptions, limitations and methods that support a Project and assessing whether the Project conforms to the criteria set forth in the Isometric Standard and the Protocol by which the Project is governed. Validation must be completed by an Isometric approved third-party (VVB).

A process for evaluating and confirming the net Removals and Reductions for a Project, using data and information collected from the Project and assessing conformity with the criteria set forth in the Isometric Standard and the Protocol by which it is governed. Verification must be completed by an Isometric approved third-party (VVB).

Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.

A collection of Removal or Reduction processes that have mechanisms in common.

A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.

The concentration of inorganic carbon dissolved in a fluid.

The period of time over which a Project Design Document is valid, and over which Removals or Reductions may be Verified, resulting in Issued Credits.

A chemical substance used for construction that sets, hardens, and adheres to other materials to bind them together. Ordinary Portland Cement (PC) is the most common cement used in modern concrete. Other types of cement include Ground Granulated Blast-furnace Slag (GGBS), Pulverised Fly Ash (PFA) and natural pozzolans.

Standard physical constants as well as standard values set forth by bodies such as the National Institute of Standards and Technology (NIST) or others.

A standards organization that develops and publishes voluntary consensus international standards.

LiDAR is a remote sensing technology that uses laser pulses to create highly accurate three-dimensional maps of forest structure, enabling measurements of tree height, canopy density, and biomass.

A remote sensing technology which uses radio waves to create images of the earth’s surface.

A satellite-based navigation system.

The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.

Underground Injection Control

A common and recognized insurance mechanism among Registries allowing Credits to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.

A database that holds information on Verified Removals and Reductions based on Protocols. Registries Issue Credits, and track their ownership and Retirement.

A document submitted alongside Claimed Removals and/or Reductions that details the calculations associated with a Removal or Reduction, including the Project's emissions, Removals, Reductions and Leakages, presented together in net metric tonnes of CO₂e per Removal or Reduction.

Purposefully erring on the side of caution under conditions of Uncertainty by choosing input parameter values that will result in a lower net CO₂ Removal or GHG Reduction than if using the median input values. This is done to increase the likelihood that a given Removal or Reduction calculation is an underestimation rather than an overestimation.

A period during which a Project has any obligations, under the selected Protocol, to submit ongoing Monitoring data to Isometric and the VVB.

Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.

The document, written by a Project Proponent, which records key characteristics of a Project and which forms the basis for Project Validation and evaluation in accordance with the relevant Certified Protocol. (Also known as “PDD”).

713.0 Appendix 1: Monitoring Plan Requirements

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 theThe Project activity during theThe 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.

14.0 Appendix 2: Approved Permitting Regimes

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

Current approved permits:

• U.S. EPA Underground Injection Control (UIC) Class VI¹⁹
• EU directive 2009/recovery31/EC testing(including followedsubsequent byguidance documents)²⁰
• Norway licence for exploitation of a series of instantaneous pressurized slug/pulse withdrawal tests or wireline geophysical surveys.3.1.3.2 (CO2 Storage via In-Situ Mineralization)Reservoir modelingModeling of thesubsea reservoir includingfor pressurestorage and fracture simulation to assessof CO₂²¹
• North migrationSea andTransition behavior and to ensure containment. Including a predictive componentPre InjectionAuthority, OperationUnderRegulation certain conditionsOperation requiredModel type, inputs and outputs2.2, 3.1.3.32010 (CO2SI Storage2010/2221) via²²
• Alberta In-SituEnergy MineralizationRegulator (AER) Directive 064 ²³²⁴

815.0 Relevant Works