CO₂ Storage in Saline Aquifers

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 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.

2.3 Site characterizationsCharacterization

As part of the permit application, 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 the geologic system:

• Includes a sequestration zone of sufficient volume, porosity, permeability, and injectivity to receive the total anticipated volume of the CO₂;.
• Includes a confining system free of transmissive faults and fractures and of sufficient extent and thickness to contain the injected CO₂, displaced formation fluids and any gas generated (if gaseous CO₂ is not injected), and allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); includes a confining system composed of a layered interval of low and moderate permeability rocks that 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;.
• 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.

In addition, characterization of site geology and geochemistry, potential interaction of the injected CO₂ and in-situ fluids and injectant mobility and reservoir simulations will be required.

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

Table 1: List of baseline characterization requirements.

Long-term stability justification must be completed in conjunction with performance monitoring of the formation, such as pressure front monitoring, to ensure fracturing and resulting mobility are not occurring. Specific laboratory core analysis experiments with relevant cores could be conducted to confirm suitability for CO₂ sequestration operations, including quantification of CO₂ reactivity with the core, especially with regards to reductions in permeability and secondary trapping mechanisms (residual, solubility and mineral trapping). The laboratory experiments may also include quantification of the rate at which CO₂ migrates, dissolves in water or precipitates as carbonate minerals. A relevant core would ideally be a core directly sampled from the Project site.

Site characterizations and analytical modeling shall be reviewed every 5 years as part of the regulators permit renewal application minimum, or at the Regulators Programs Director’s request, 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 shall 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

• MaximumInjection operation pressures must be below the 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 pressuresand shall 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.

• Maximum CO₂ injection rate to monitor volumes injected, prevent induced seismicity or return of injectant. 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.
  • 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.
  • More information can be found within Section 7 in the relevant protocols5.0.

• 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 [C]:

  • Temperature
  • CO₂ concentration as described within Section 7 of the relevant protocols5.0.
  • Identification of impurities that might alter corrosivity, properties of the injectate downhole, or reactivity with the reservoir rocks/fluids (e.g., arsenic, hydrogen sulfide, mercury)
  • pH (for dissolved CO₂ injections)
  • Viscosity (for dissolved/ supercritical injections)
  • If dissolved CO₂ is being injected, it is recommended that major & minor ions and δ¹⁸O, δD are also be measured

• 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 monitoringtheir suitability for athe gaseoussite releaseconditions (CO2,in hydrocarbonsthe PDD [C].

Detectors/alarms may be placed on the injection wellhead or othera GHGsmonitoring 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). IfThe activated the operatorOperator 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. VVBWhere 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].

3.1.2 System Integrity Monitoring

• ACorrosion demonstrationmonitoring ofmust internal mechanical integritybe performed and reported every 6 monthsquarterly. This includes identifying any loss of mass and/or thickness, cracking, pitting, or 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 from 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 leakageleaks pathway [A, D].
• A pressure fall-off test every two years [A, annuallyD].
• Continuous monitoring of pressure within the wellbore annulus [A, D].

3.1.3 Migration and Storage Reversal Monitoring

As applicable based on specific site conditions, formation type, and permit class, monitoring is to ensure CO₂ migration beyond the AOR within the target reservoir 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 Onshore Monitoring

3.1.3.1.1 Surface Monitoring

Surface monitoring, where required by permit, mustshould be completed at a site-specific frequency and spatial distribution inby orderthe permitting regime to monitor any CO₂leakage leaks[A]. This includes monitoring of:

• Surface displacement, which can inform on pressure changes or geomechanical impacts from CO₂ injection, and when compared to reservereservoir 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) has been 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.

• Ecosystem stress, which can be an early indicator for CO₂leakageleaks. This should be monitored continuously with ad hoc random on-site verification 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 images⁹.

• Surface CO₂ density and flux measurements to identify large point-source leaks, may be required to ensure compliance with regulations on potential risks to USDWs or by local regulators. Monitoring frequency and spatial distribution shall 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 CH₄, radon, noble gasses, and isotopes of CO₂ or introduced tracers, such as δ¹³C of CO₂/CH₄, provide a unique fingerprint for the CO₂ that can be identified in above ground emissions^10,11.

3.1.3.1.2 Near Surface Monitoring

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

• Geochemical monitoring of USDWs ismay be required periodicallyby (aspermit, agreedand inshould theincluding monitoring plan with the regulating authority) for groundwater quality and geochemical changes that may result from carbon dioxide or formation fluid movement through the confining zone(s). It is recommended that at a minimum fluids should be sampled for:

  • pH
  • Temperature
  • Density
  • Conductivity or other salinity measurement
  • Dissolved gas concentrations (i.e., CO₂)
  • TDS

• Additional monitoring in USDWs could include: major anions and cations, select trace metals, volatile organic compounds, stable isotopes of C in CO₂, CH₄ (if present) and DIC, impurities identified in the injected CO₂ (e.g., hydrogen sulfide), dissolved oxygen, δ¹⁸O and δD of H₂O, and other inherent/added tracer concentrations (e.g., δ¹⁴C, noble gasses) and any other constituents identified by the owner or operator and/or the regulators.

3.1.3.1.3 Subsurface Monitoring

Subsurface monitoring is required to monitor the temperature and pressure within the reservoir as well as detect and monitor the lateral extent and boundaries of injected CO₂ migration within the storage reservoir to ensure that the plume stays within the target reservoir. Additionally, it can inform on the behavior and secondary trapping of CO₂ within the reservoir. Plume and pressure-front monitoring results also provide necessary data for comparison to and verification of model predictions, if major deviations from the model are observed, operations should be modified to try and increase secondary trapping (e.g., residual/solubility/mineralization) and/or update monitoring plan. The owner/operator will use a site-specific and complementary suite of methods to trace the carbon dioxide plume and area of elevated pressure. Available methods for plume and pressure-front tracking include: (1) fluid pressure and temperature monitoring (in-situdirect); (2) geophysical monitoring (indirect); (3) groundwater geochemical monitoring (in-situdirect); and (4) computational modeling (indirect). Monitoring should include both direct and indirect monitoring [A,B,C].

• Indirect methods should include reservoir imaging (e.g., seismic, gravity and/or electrical methods) which should be chosen based on their response to predictions in reservoir & geological models and storage simulations, and compared against the baseline conditions. This will be required to track the presence or absence of elevated pressure within the injection zone and the extent of the carbon dioxide plume, unless the regulator determines that such methods are not appropriate. Indirect monitoring of plume migration should be condoncuted every 5 years. If not appropriate additional direct monitoring may be required.
• Direct methods should include continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) to show vertical containment within the storage reservoir. Temperature and pressure should be logged continuously, for example temperature could be measured through a fiber-optic distributed temperature sensing system. Pressure and temperature monitoring in the zone immediately above the sealing interval is also recommendedrequired. PeriodicA (6pressure monthly)fall-off measurementtest ofshould formationbe waterconducted density,every 2 years to determineassess thereservoir likelihood of clogging may also be requiredinjectivity.

• Where indirect monitoring is not appropriate or there may be risks associated with the dissolved-phase plume [A], the regulators or certified geologist may determine the use of geochemical monitoring necessary to track the CO₂ plume extent. Formation fluid pH and conductivity must be measured prior to injection. Geochemical analysis can also help determine the behavior of CO₂ in the subsurface. For example, pH can impact CO₂ solubility (how much CO₂ will dissolve) as well as water rock interactions (how much CO₂ will mineralize). Gas composition is important to identify if any modification occurred in the subsurface. TheseFormation fluid measurements could include but are not limited to:

  • pH
  • Conductivity
  • Gas/dissolved gas composition including DIC (to determine fluid saturation states as calculated by thermodynamic principles, to see if these conditions are conducive for mineralization)
  • Any other tracers used (e.g., δ13C-CO2 or DIC, major and minor ions,δ18O-H2O, δD-H20)Density

• Reservoir modeling must be performed, including pressure and fracture simulations. This could be either using traditional reservoir models or CCSNET ai models¹². 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 layer, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment CO₂ within targeted injection zone. Reservoir models must be updated as operational data changes [A,B,C].

• Monitoring of the wellhead pressure continuously.
• At a minimum, all projects are required to monitor for seismic activity caused by operations using regional seismic data and compositionreport any seismic events of anymagnitude gas recovered from well(s)2.7 or representativegreater sampling locations where detection of gasses from the reservoir must be completed[B]. GasAn composition monitoring shall include CO2 and CH4 emissions from the storage reservoir via CO2 and CH4 gas monitors with a resolution of at least 0.01 vol%, or lab analysis, if sampled. Results must be compared to baseline values obtained prior to CO2 injection. Sampling frequency should be monthly [B,C].
• Aadditional seismic monitoring program may be suggested at the discretion of the UIC directorregulator or equivalentcertified 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. TheSeismic purposemonitoring ofcan thisbe isused 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].

3.1.3.2 Offshore Monitoring

3.1.3.2.1 Surface Monitoring

Surface monitoring, where required by permit, should be completed at a site-specific frequency and spatial distribution indetermined orderby the permitting regime to monitor anyfor CO₂leakageleaks. This should include measurement of CO₂ density and flux to identify large point-source leaks for example by [A]:

• Inherent tracers (such as CH₄, radon, noble gasses, and isotopes of CO₂) or introduced tracers (e.g., δ¹³C of CO₂/CH₄), to provide a unique fingerprint for the CO₂ that can be identified in the case of leakageleaks at the ocean floor¹⁰.
• pH monitoring using techniques such as using eddy covariance, pH sensors on remotely operated vehicles/autonomous underwater vehicle, or water sampling¹³.

3.1.3.2.2 Subsurface Monitoring

• Subsurface monitoring is required to monitor the temperature and pressure within the reservoir as well as detect and monitor the lateral extent and boundaries of injected CO₂ migration within the storage reservoir to ensure that the plume stays within the target reservoir. Additionally, it can inform on the behavior and secondary trapping of CO₂ within the reservoir. Plume and pressure-front monitoring results also provide necessary data for comparison to and verification of model predictions, if major deviations from the model are observed, operations should be modified to try and increase secondary trapping (e.g., residual/solubility/mineralization) and/or update monitoring plan. The owner/operator will use a site-specific and complementary suite of methods to trace the carbon dioxide plume and area of elevated pressure. Available methods for plume and pressure-front tracking include: (1) fluid pressure and temperature monitoring (in-situdirect); (2) geophysical monitoring (indirect); and (3) computational modeling (indirect). Monitoring should include both direct and indirect monitoring [A,B,C].

  • Indirect methods should include reservoir imaging (e.g., seismic, gravity and/or electrical methods) which should be chosen based on their response to predictions in reservoir & geological models and storage simulations, and compared against the baseline conditions. This will be required to track the presence or absence of elevated pressure within the injection zone and the extent of the CO₂ plume, unless the regulator determines that such methods are not appropriate. Indirect monitoring of plume migration should be conducted every 5 years. If not appropriate additional direct monitoring may be required.
  • Direct methods should include continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) to show vertical containment within the storage reservoir. PeriodicPressure (6monitoring monthly)in measurementthe ofzone formationimmediately waterabove density,the sealing interval is also required. A pressure fall-off test should be conducted every 2 years to determineassess thereservoir likelihood of clogging may also be requiredinjectivity. Temperature and pressure should be logged continuously, for example temperature could be measured through a fiber-optic distributed temperature sensing system.

• Reservoir modeling must be performed, including pressure and fracture simulations. This could be either using traditional reservoir models or CCSNET aiAI models¹². 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 layer, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment of CO₂ within targeted injection zone. Reservoir models must be updated as operational data changes [A,B,C].

• Monitoring of the wellhead pressure continuously.
• At a minimum, all projects are required to monitor for seismic activity caused by operations using regional seismic data and compositionreport any seismic events of anymagnitude gas recovered from well(s)2.7 or representativegreater sampling locations where detection of gasses from the reservoir must be completed[B]. GasAn composition monitoring shall include CO2 and CH4 emissions from the storage reservoir via CO2 and CH4 gas monitors with a resolution of at least 0.01 vol%, or lab analysis, if sampled. Results must be compared to baseline values obtained prior to CO2 injection. Sampling frequency should be monthly [B,C].
• Aadditional seismic monitoring program may be suggested at the discretion of the UIC directorregulator or equivalentcertified 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. TheThis purposeshall include deeper wireline or cemented subsurface geophones for microseismic monitoring and could be combined with at/near ground level stations as part of thisan isintegrated 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].

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.

3.1.3.3 Triggered Gas Investigation

When the continuous gas detection system (Section 3.1.1.1) detects gases, 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 or equivalent sample). 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 leakageinjection. Wellhead pressure should be monitored continuously, and wellhead gas sampling should be monthly [B,C].

3.1.3.4 CO₂ Leaks

The Project Proponent/Operators 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 competent permitting authority. If any CO₂leakage is detected from the target reservoir or there are significant irregularities from the used model(s)occurs, the Project Proponent/operatorsOperators must undertake corrective measures as set out in theirthe monitoringemergency response plan submitted and approved by the competent authority. For a loss of conformance with models, the Project Proponent must halt injection whilst they identify the cause of this loss, and then revise the monitoring plan to account for this change of migration. If there is a leak the Project Proponent must halt injection whilst they conduct an assessment to determine if the loss of containment can be repaired prior to injection beginning again. The amount of CO₂ lost must also be quantified and subtracted from the overall total of CO₂ storedstorage.

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 migration of the CO₂ plume is unexpected and suggests potential movement of CO₂ outside the target formation
• CO₂ migration into the caprock and zones above the target formation
• Actual CO₂ plume or elevated pressure extend beyond analytical model expectation because any of the following has occurred:
  • An earthquake of magnitude 2.7¹⁴ or greater within the AOR;
  • A 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 is used, 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 usinginclude reservoir modeling alongside both indirect seismic imaging and direct measurements from the injection well of formation fluid temperature and reservoir pressure and pressure in the zone immediately above the sealing interval to trace plume migration and the pressure front. USDWsSeismic shouldmonitoring alsousing regional seismic data must continue, and events of magnitude 2.7 or greater must be monitoredreported. toCorrosion identifymonitoring and address any leakage pathways that arise. It is recommended thatexternal mechanical integrity oftesting monitoringmust wellsbe and the injection well occursconducted annually for the first three years after injection. ceasingAnnulus pressure must initially be measured monthly. A pressure fall-off test must initially be conducted every two years. It is recommended that USDWs be monitored to identify and everyaddress fiveany yearsleak untilpathways sitethat decommissioning, to ensure they do not become a leakage pathwayarise. 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 montiroing plan. Such criteria could include the reservoir pressure reaching a certain level relative to pre-injection conditions or steady or favorable trends in observed geochemical monitoring results over a predefined period, and agreement with model predictions.

After a minimum of 15 years (USA) or 20 years (EU) or equivalent, an assessment must be completed to demonstrate plume stabilization or a trend towards stabilization. Re-assessments must be carried out until permanent containment of the stored CO₂ is demonstrated in order to eliminate the risk of migration or release of CO₂ from the storage formation to the atmosphere or USDWs [addresses risk A]. The Project Proponent will actively explore emerging technologies for measuring plume stabilization. The plume stabilization assessment shall be conducted in one of the following ways:

• Perform geophysical monitoring of the CO₂ plume to demonstrate limited change since the cessation of injection.
• Predicted timeframe for pressure decline within the injection zone.
• Utilize predictive modeling, where deemed appropriate by Isometric and/or the regulating body and/or the certified geologist who approved the monitoring plan, based on monitoring data collected during post-injection monitoring to demonstrate the stability of the CO₂ plume and lack of plume migration in the formation that would present a risk to water sources in the AOR.
  • Modeling must be validated by comparison to historical monitoring data including subsurface pressure and plume migration.
  • Models must utilize site specific geochemistry and CO₂ characteristics from analyses required in Section 1 and Section 2.2 of this Module.
  • Models must assess the potential plume extent after 50 years and demonstrate that the plume will not migrate beyond the target reservoir, impact drinking water sources or cause other environmental harms.
  • Comparison of model to predictions made at the time a site decommissioning plan was approved.
• Where conditions of the formation and existing monitoring wells allow, tracer studies may be utilized to demonstrate 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 target reservoir.
• Or new methods as outlined in subsequent protocolProtocol 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 whether plume stabilization is demonstrated. If the regulating authority does not have guidance on the minimum timeframe, this is set at a minimum of 50 years. The length of ongoing monitoring will be subject to change given subsequent reanalyses.

If the plume stabilization 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 plume will be considered stabilized and the site decommissioned following requirements in Section 38.70.

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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 caprock or well integrity, and this technology does not yet have a documented history of reversals. There is, however, a risk of methane production within the reservoir, based on current literature, but this risk is very small⁸. AsBased on present levels of scientific knowledge, ++Projects applicable to this Module are typically categorized as having a result,Very Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire (also found in the relevant Protocol). This results in a 21%  buffer pool 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++, 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 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 should 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.

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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 [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 1)

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 reportingReporting periodPeriod, [math: RP].
• [math: Δt] = the time interval the average is taken over.

The mass of CO₂-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 2)

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 (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

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.

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 reportingReporting periodPeriod, 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.

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 reportingReporting periodPeriod, [math: RP];
• Analytical results for each supporting gaseous injectant analysis specified in Section 3.4;
• 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 injection facility or Project Proponent and provided for verification purposes for a minimum of five years after the monitoring period.

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

Type: Emissions

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

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

3

8.70 Closure Requirements

During decommissioning, the Project Proponent shall 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, for example multiple plugs of CO₂ resistant cement, and to the regulators requirements.

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 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 CO₂leakagesleaks or significant irregularities. This will be intensified if CO₂ leakagesleaks or significant irregularities are identified. If operating in other jurisdiction, the relevant regulations regarding liability must be followed and disclosed within the PDD.

3

9.80 Recordkeeping

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

AllRecords recordsof shalllaboratory 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 10five years after the wellend closureof the monitoring period. 

All closure and post-closure monitoring records shallmust 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.

410.0 Acknowledgements

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

511.0 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 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.

The increaseterm inused GHGto describe greenhouse gas emissions outsideto the geographicatmosphere as a result of Project activities.

An activity or temporalprocess boundaryor group of activities or processes that alter the condition of a projectBaseline and leads to Removals or Reductions.

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

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

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.

A collection of Removal or Reduction processes that project'shave activitiesmechanisms in common.

A lack of knowledge of the exact amount of CO₂ removed by a particular process, Uncertainty may be quantified using probability distributions, confidence intervals, or variance estimates.

The escape of CO₂ to the atmosphere after it has been stored, and after a Certificate 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 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.

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

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

A document that describes how to quantitatively assess the net amount of CO₂ removed by a process. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the Carbon Fluxes involved in the CDR process. A Protocol measures the full carbon impact of a process against the Baseline of it not occurring.

Enhanced hydrocarbon recovery (EHR) is a tertiary hydrocarbon production technique or process where the physicochemical (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 use of CO₂ injection for EHR where the CO₂ remains stored in the geologic formation permanently (IEA, 2015).

Underground Injection Control

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

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.

The concentration of inorganic carbon dissolved in a fluid.

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.

Thosefor gaseousopen constituentssystems, ofbiogeochemical and/or physical interactions which occur during the atmosphere,removal both natural and anthropogenic (human-caused),process that absorb and emit radiation at specific wavelengths withindecrease the spectrumCO₂ ofremoval terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).

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

A remote sensing technology which uses 2+ SAR images to generate maps of the earth’s surface.

A satellite-based navigation system.

AThe processuse forof evaluatingsatellite, aircraft and confirmingterrestrial deployed sensors to detect and measure characteristics of the netEarth's Removalssurface, as well as the spectral, spatial and Reductionstemporal foranalysis aof Project, usingthis data andto informationestimate collected from the Projectbiomass and assessingbiomass 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)change.

ALiDAR systematicis 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 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)biomass.

Total Dissolved Solids.

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 Certificates to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.

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

A database that holds information on Verified Removals and Reductions, and reviewed EACs, based on Protocols. Registries Issue Certificates, 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.

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

Those gaseous constituents of the atmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the spectrum of terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).

A publicly visible uniquely identifiable Credit Certificate Issued by a Registry that gives the owner of the Credit the right to account for one net metric tonne of Verified CO₂e Removal or Reduction. In the case of this Standard, the net tonne of CO₂e Removal or Reduction comes from a Project Validated against a Certified Protocol.

OptoelectronicA devicesUnited whichStates measureGovernment temperatureagency usingthat opticalprotects fibreshuman ashealth sensors,and providingthe a continuous temperature profile over kilometer distances.

Inductively Coupled Plasma Mass Spectrometry: An analytical technique used to measure elements at trace levels within a sampleenvironment.

613.0 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 carbon dioxide removal. Following this guidance will ensure the Project Proponent measures and confirms carbon dioxide 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 Credits.

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.

714.0 Appendix 2: Approved Permitting Regimes

Permits which are currently approved by Isometric are listed below. 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 VI¹⁵
• EU directive 2009/31/EC (including subsequent guidance documents)¹⁶
• Norway licence for exploitation of a subsea reservoir for storage of CO₂¹⁷
• North Sea Transition Authority, Regulation 2010 (SI 2010/2221) ¹⁸
• Alberta Energy Regulator (AER) Directive 064 ¹⁹²⁰

15.0 Relevant Works

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

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

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

EUR-Lex (Access to European Union Law). (2009). Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No 1013/2006. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:32009L0031