CO₂ Storage in Saline Aquifers

1.0 Introduction

Durability (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.) refers to the length of time for which carbon dioxideCO₂ is removed from the Earth’s atmosphere and therefore cannot contribute to further climate change. This module (Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.) details durability and monitoring requirements for storage (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”.) of CO₂ removed from the atmosphere and stored in saline aquifers.

CO₂ can be injected into saline aquifers as a gas, supercritical fluid, dissolved in water or in exceptional circumstances liquid CO₂. The behavior of CO₂ in the reservoir (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).) (i.e., trapping mechanisms) will depend on the injected phase, formation water chemistry and the type of reservoir the CO₂ is injected into (i.e., siliciclastic vs carbonate vs volcanogenic sandstones). To ensure sufficient durability, CO₂ characteristics and the conditions within the storage reservoir must be well defined, modeled (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.) and monitored.

Within saline aquifers, injected CO₂ is prevented from vertically migrating by structural or stratigraphic barriers such as low permeability caprocks (such as anhydrite or shale) or structural features (such as faults). This method of containment of CO₂ is known as physical trapping. CO₂ can also become trapped within the pore space of the reservoir preventing its migration as CO₂ is held in-place, this is known as residual trapping. Through time physically trapped CO₂ will become chemically trapped, eliminating its inherent buoyancy and associated risk of mobility. One type of chemical trapping is by dissolution (solubility trapping) into the formation waters, this increases the density of injected CO₂, meaning it will sink in a reservoir. Mineral trapping (another form of chemical trapping) removes dissolved CO₂ from fluids and permanently immobilizes injected carbon dioxide in solid carbonate minerals. The reduction of CO₂ mobility through these subsequent chemical trapping mechanisms reduces the risk of reversibility associated with breaks in the seal. Once CO₂ is trapped within the reservoir and there is proof of no migration outside the target reservoir or to Underground Sources of Drinking Water (USDWs) (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.) after closure (as per regulating permitting requirements) within the Area of Review (AOR) (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.)¹, the carbon dioxide can be considered geologically removed.

This module is applicable for gaseous, supercritical and water-dissolved CO₂ injections into permeable sedimentary systems (such as siliciclastic sandstones, carbonates and volcanogenic sandstones).

Potential risks to expected durability are site specific, but generally fall under three categories: CO₂ mobility [risk A], pressure changes [risk B], and chemical changes [risk C]. Specific risks may include:

• Injected CO₂ plume migration out of the intended storage reservoir [risk A].

  • The CO₂ plume will migrate within the reservoir and the injected plume could migrate further or have more limited trapping mechanisms than the reservoir model initially predicts. Reservoir models and injection procedures should be updated during monitoring to specify injection and reservoir management parameters, ensuring containment of the CO₂ within the target reservoir.
  • It is not possible to see dissolved CO₂ through geophysical monitoring techniques. If this trapping is a major contributor on a reservoir scale, then distinguishing it from other non-CO₂ saturated fluids is not possible. Direct measurements of the reservoir should therefore be combined with indirect geophysical monitoring. If dissolved CO₂ stays within the target reservoir it will be considered removed.

• CO₂ injection causes a breach in seal integrity which could result in leakage (The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities.)CO₂ into overlying aquifers and the surface [risk B].

  • Changes in the stress field within the reservoir both during and post CO₂ injection can lead to reservoir and caprock mechanical failure. Faults within the caprock represent one of the possible pathways for CO₂ to migrate out of the storage reservoir and the greatest likelihood of fluid migration is during or immediately after activation/reactivation². Caprock failure has also been linked to changing thermomechanical and hydromechanical processes such as two-phase fluid flow³, the presence of heterogeneities⁴, temperature changes⁵, and/or geochemical interactions (such as mineral precipitation or dissolution)⁶. The seal integrity must be thoroughly characterized prior to injection and monitored throughout.
  • Induced microseismicity as large volumes of CO₂ being injected into brittle reservoirs within a few kilometers of the surface may trigger seismic events⁷. This potential risk is likely lower within soft sedimentary basins⁸. However, even small seismic events have the potential to damage the seal and create leakage⁹.

• Injected CO₂ interacts with reservoir fluids/rocks changing its behavior/form or the reservoir properties [risk C].

  • CO₂ injection into saline aquifers can lead to salt precipitation from the drying of formation water resulting in a reduction in reservoir permeability from clogging. Salt precipitation near the injection well can lead to a reduction in permeability and change in injectivity.
  • Water-rock interaction results in partial dissolution of host-rock. This can have a small impact on permeability, however over the area of the target formation it could feed into any uncertainties surrounding CO₂ and fluid migration.
  • Formation of gaseous CO₂ (if dissolved or supercritical CO₂ is injected) and/or biogas (e.g., CH₄)
    • If supercritical or dissolved CO₂ is injected it is possible that changes in reservoir pressure and temperature could result in the exsolution of some gaseous CO₂. In addition, CO₂ could be microbially consumed to form CH₄, acetate or biomass. The availability of hydrogen within saline aquifers will likely be small and thus it is unlikely that there will be any CH₄ formation¹⁰. Any signs of bio-gas formation and CO₂ gas exsolution should be monitored as part of the post-injection monitoring plan (see Section 3.2). Any releases of gasses (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.) from the geologic reservoir (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.) must be accounted for as detailed in Section 3.3.

This section outlines requirements for evaluating CO₂ injection and storage within saline aquifers, with a focus on site characterization, construction and monitoring. The post-injection monitoring plan detailed in Section 3.2 acts to address and mitigate these potential risks to durability. Section 3.3 addresses accounting for any emissions associated with these risks.

Monitoring of the injection site needs to be completed to ensure that any injected CO₂ remains stored within the confines of the storage reservoir and does not migrate outside of the targeted formation, nor converted into gasses that may later be re-emitted (e.g., CO₂, CH₄). The injection site shall be monitored in accordance with the country/region specific well permitting requirements as specified in the operating permit for the injection site issued. Each site should create a “testing and monitoring plan” which incorporates available, site-specific techniques that support the overall goals of detecting trends or events that might lead to endangerment of underground sources of drinking water (USDWs) and demonstrates that the project (An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.) is operating as permitted¹¹. This plan should be submitted to the regulating authorities.

The subsurface monitoring approach developed and implemented by the Project Proponent (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) shall address the following, via the permitting process and permit compliance, or by additional efforts and documentation.

• Geologic Reservoir and Site Characterization: the proposed storage site must have been properly characterized to demonstrate site suitability for storage and containment of CO₂. This characterization should include the following conditions to act as baseline (A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.) measurements against which to compare future monitoring (Table 1).

Table 1. See Section 2.2 for further details.

• Injection Site Construction and Performance: the proposed storage site and injection system must be properly designed, including design and specification of wellbore and well materials to ensure proper long term operation of the well when injecting CO₂ and protection of any potable aquifers.
• Injection System Operation & Monitoring: the Project Proponent must specify operating conditions and monitoring systems and approaches, such as allowable wellhead pressures, gas detection, and other systems to ensure that injected CO₂ remains in the geologic formation, the formation is not negatively impacted by operations, automatic safety precautions are in place to minimize potential for exceeding allowable operating conditions, and conditions can be monitored for compliance or deviation from requirements. Reporting of operations will be in accordance with the governing/regulating body.
• Closure and Post-Closure Plan: requirements for proper closure of the storage reservoir and injection facility; as well as post closure requirements and post-injection monitoring to ensure CO₂ remains sequestered durably in the storage reservoir, the site is properly monitored, and any non-compliance is addressed with corrective actions.

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

2.0 Permitting and Site Characterization

2.1 Permitting Requirements

The injection site must have a current well permit issued by the responsible authority for the location of the injection facility and reservoir, for example within the USA a Class VI well permit from the EPA or authorized primacy state level governing agency is required. The permit must specifically identify CO₂ as acceptable injectants under the permit. In addition, the project must comply with all applicable local environmental, ecological and social requirements as well as those set out in Section 5 of the DAC protocol and Section 3.7 of the Isometric Standard. Wells may not be utilized if the wells are also used for enhanced hydrocarbon recovery (EHR or EHR+) (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).) activities.

2.2 Site Characterization and Feasibility Requirements

The site should be well characterized in accordance with the permit application and approval requirements under the national/international regulations. If there is a lack of distinct relevant local regulations to meet the minimum requirements of this module, Project Proponents are required to follow either the U.S. EPA Underground Injection Control (UIC) or EU directives. All projects are required to clearly report the regulations for which are utilized at the site, with any deviations from the relevant national/international standards outlined within the project PDD document upon submission to the relevant 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.).

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

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 methods that include but are not limited to:

• Baseline geophysical surveys, in accordance with the agreed monitoring plan, should be conducted during site characterization, to allow for changes in the subsurface induced by the injection operation to be assessed.
• Onsite characterization well which may include drilling, coring or logging to understand reservoir characteristics and fluid saturation.
• Formation fluid composition including but not limited to temperature, pH, conductivity.
• Surface elevation models.
• Soil or seafloor gas composition and fluxes, where applicable, over a period of year to characterize any background spatial and temporal trends and variability.
• Geochemical composition of USDWs within the AOR, where appropriate and required in the permit, this must include but is not limited:
  • pH
  • Temperature
  • Dissolved gas concentrations
  • Conductivity
  • Total dissolved solids (TDS)
  • Density
• Baseline ecosystem imaging, where applicable and required by the permit.

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.

2.3 Well Construction Requirements

The Project Proponent must ensure that the injection well is constructed in compliance with the regulators permit and documentation and records of well construction are maintained and available for review.

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

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

Casing, cement, tubing, packer, wellhead, valves, piping, or other materials used in the construction of each well associated with the project must have sufficient structural strength and be designed for the life of the project. All surface casing will be set below the lowermost USDW and cemented to the surface. All well materials must be compatible with fluids with which the materials may be expected to come into contact, including CO₂ and formation fluids (e.g., corrosion-resistant well casings and CO₂ resistant cement) and must meet or exceed standards (Standard physical constants as well as standard values set forth by bodies such as the National Institute of Standards and Technology (NIST) or others.) developed for such materials by API, ASTM International, or comparable standards. The casing and cementing program must be designed to prevent the movement of fluids out of the sequestration zone and above the storage complex.

3.0 Monitoring

3.1 Injection and Operational Monitoring Requirements

The Project Proponent will ensure that the injection facility complies with the well permit, including the development and implementation of the well operating plan as required by the permit. This plan should be updated every five years, unless the regulatory body that issues the permit requires this to be updated more often, to take account of changes to the assessed risk of leakage, changes to the assessed risks to the environment and human health, new scientific knowledge, and improvements in best available technology. The risk (Section 1) addressed by each measurement will be denoted in square brackets. At a minimum, the permit and associated well operating plan shall consider the following:

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 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 protocols.

• 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]:

  • pH and temperature
  • CO₂ concentration as described within Section 7 of the relevant protocols
  • 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).
  • Viscosity (for dissolved/ supercritical injections).
  • If dissolved CO₂ is being injected, it is recommended that major & minor ions and δ¹⁸O, δD should 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.

• RequiredWells must have gas detectors (or equivalent sensors/imaging) with alarms and automatic surfaceinjection shut-off systems (e.g., automatic shut-off, checkor valves)procedures in place for wells,manual orshut otheroff mechanicalof devices that provide equivalent protectioninjection/operation), including, at a minimum, injection pump shutoff when maximum pressure is reached, or maximum flow rate is exceeded, orand gasmonitoring detectionfor systemsa indicategaseous elevatedrelease CO2(CO2, hydrocarbons or CH4other levelsGHGs). If activated the operator must immediately investigate and identify as expeditiously as possible (or in headspaceaccordance [Bwith permit requirements) the cause of the alarm or shutoff,C] and report the instance to the validation and verification body (VVB).

3.1.2 System Integrity Monitoring

• A demonstration of internal mechanical integrity performed and reported every 6 months. 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].
• 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 leakage pathway [A].
• A pressure fall-off test, annually [A].

3.1.3 Migration and Storage Reversal Monitoring

As applicable based on specific site conditions, formation type, and permit class, monitoring 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 is required at a site-specific frequency and spatial distribution in order to monitor any CO₂ leakage [A]. This includes monitoring of:

• 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/InSAR). 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, where applicable, which can be an early indicator for CO₂ leakage. This should be monitored continuously with ad hoc random on-site 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).) to validate (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).) any anomalies. Continuous monitoring could either be done via site based phenocams or medium-to-high resolution remote sensing and compared to baseline images¹².

• Surface CO₂ density and flux measurmentsmeasurements 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^13,14.

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 underground sources of drinking water (USDW) [A]. This includes monitoring of:

• Geochemical monitoring of USDWs is required periodically (as agreed in the monitoring plan with the regulating authority) for groundwater quality and geochemical changes that may result from carbon dioxide or 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-situ); (2) geophysical monitoring (indirect); (3) groundwater geochemical monitoring (in-situ); 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. 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 recomended. Periodic (6 monthly) measurement of formation water density, to determine the likelihood of clogging may also be required.

• Where indirect monitoring is not appropriate or there may be risks associated with the dissolved-phase plume [A], the regulators may determine the use of geochemical monitoring necessary to track the CO₂ plume extent. 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. These 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 mineralisation)
  • Any other tracers used (e.g., δ¹³C-CO₂ or DIC, major and minor ions,δ¹⁸O-H₂O, δD-H₂0)

• Reservoir modeling must be performed, including pressure and fracture simulations. This could be either using traditional reservoir models or CCSNET ai models¹⁵. 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 [A,B,C].

• Monitoring of the wellhead pressure and composition of any gas recovered from well(s) or representative sampling locations where detection of gasses from the reservoir must be completed. Gas 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].
• A seismic monitoring program may be suggested at the discretion of the UIC director or equivalent 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 intergrated strategy.The purpose of this is 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 is required at a site-specific frequency and spatial distribution in order to monitor any CO₂ leakage. 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 leakage at the ocean floor¹⁶.
• pH monitoring using techniques such as using eddy covariance, pH sensors on remotely operated vehicles/Autonomous underwater vehicle, or water sampling¹⁷.

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-situ); (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 carbon dioxide plume, unless the regulator determines that such methods are not appropriate. 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. Periodic (6 monthly) measurement of formation water density, to determine the likelihood of clogging may also be required. 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 ai models¹⁸. 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 [A,B,C].

• Monitoring of the wellhead pressure and composition of any gas recovered from well(s) or representative sampling locations where detection of gasses from the reservoir must be completed. Gas 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].
• A seismic monitoring program may be suggested at the discretion of the UIC director or equivalent in areas of increased seismic risk, where demonstrated that seismicity may have an impact on the formation and the long duration storage of CO₂. The purpose of this is 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 on a project-specific basis using site-specific data from site characterization and injectate composition.

3.1.3.3 LeakageCO₂ leakage

If any CO₂ leakage is detected from the target reservoir or there are significant irregularities from the used model(s), the project proponent/operators must undertake corrective measures as set out in their monitoring 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 leakageleak 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 stored.

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 2.7¹⁹ 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 3.3 and Section 3.3.1.

3.2 Post Injection Monitoring

The aim of this post-injection monitoring and the closure requirements in Section 3.5 is to put in place scientific and/or operational monitoring practices that prove beyond reasonable doubt that CO₂ storage will be durable on geologic timescales. Addressing potential risks to durability (Section 1) is important for ensuring robust and diligent carbon dioxide removals (The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.). The project proponent must follow any post-injection and site decommissioning requirements of the permit for the specified project. Post-injection is defined as monitoring between the end of injection and plugging of the wells. Once injection has ceased (e.g., this is defined as closure in the EU) the site must undergo post-injection monitoring. Once it is demonstrated that the injectate plume is stable (i.e., the plume is no longer migrating) within the storage reservoir and unable to impact the USDWs, wells can be plugged, the site decommissioned (e.g., this is defined as the closure point in the US). Within the EU, the project proponent must transfer the site to the national/local authorities where monitoring will continue. Within the USA, additional monitoring post-closure may be discontinued if allowed under the applicable UIC permit. If operating in another region, the project proponenet must follow guidance from the regulating authority.

It is recommended that for post-injection monitoring 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. This monitoring therefore must focus on using reservoir modeling alongside both indirect seismic imaging and direct measurements from the injection well of temperature and pressure to trace plume migration and pressure front. USDWs should also be monitored to identify and address any leakage pathways that arise. It is recommended that mechanical integrity of monitoring wells and the injection well occurs annually for the first three years after injection ceasing and every five years until site decommissioning, to ensure they do not become a leakage pathway. 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. 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, 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 protocol (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.) 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 3.5.

3.3 Risk of reversal

Based on present levels of scientific knowledge, projects applicable to this protocol are categorized as having a Very Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire. This is because there 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 small¹⁰. As a result, a 2% 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.) will be set aside as a precaution. This reversal risk will be reassessed every 5 years, aligning with the crediting period, or when new scientific research and knowledge are produced.

Reversals will be accounted for by projects and the Isometric Registry (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.) as detailed in Section 5.6 of the Isometric Standard.

3.3.1 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 CO₂ proportional to the mass of injected material. For example:

   • A reservoir has a total of 200t of material emplaced 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 CO₂ has been quantified to be 10t.
   • The Project Proponent must compensate for 25% (50/200) of 10t CO₂ = 2.5t of CO₂.

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

3.4 Calculation of CO₂e _{MonitoringEmissions}

[math: CO_{2}e_{Monitoring, RPEmissions}] is the total quantitygreenhouse of GHG emissions resulting from the operations and activities associated with monitoring the geologic storage of CO2 during the project operations, closure, and post closure periods. Emissions that occur during a reporting period, [math: RP] are included directly and fully in that reporting period, and are not allocated across multiple reporting periods.

Emissions are calculated as:

[math: \tag{Equation 1} CO_{2}e_{Monitoring} = CO_{2}e_{Energy, Monitoring} + \\CO_{2}e_{Transportation, Monitoring} + \\CO_{2}e_{Embodied, Monitoring} + 
\\CO_{2}e_{Misc., Monitoring} +
\\CO_{2}e_{Reversal} ]

Where

• [math: CO_{2}e_{Monitoring,}] = the total GHGgas emissions associated with storage monitoring allocated to a given Reporting Period, [math: RP], inor tonnesbatch, CO2e
• [math: CO_{2}e_{Energy,\ Monitoring,\ RP}n].

  Equations = the total GHGand emissions associatedcalculation with energy consumptionrequirements for monitoring activities, in tonnes of CO2e, see Section 3.4.2.

• [math: CO_{2}e_{Transportation,\ Monitoring,\ RP}] = the total GHG emissions associated with transportation for monitoring activities, in tonnes of CO2e, see Section 3.4.3.
• [math: CO_{2}e_{Embodied,\ Monitoring,\ RP}] = the total GHG emissions associated with embodied emissions (Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.) from construction of monitoring equipment and facilities as well as use of consumables for storage monitoring activities, in tonnes of CO2e, see Section 3.4.4.
• [math: CO_{2}e_{Misc.Monitoring,}] = the total miscellaneous GHG emissions for a given , that cannot be categorized by [math: CO_{2}e_{Energy,\ Monitoring,\ RPEmissions}], [math:including CO_{2}e_{Transportationconsiderations for monitoring activities,\ Monitoring,\are RP}]set or [math: CO_{2}e_{Embodied,\ Monitoring,\ RP}],out in tonnes CO2e.
• [math: CO_{2}e_{Reversal,}] = the totalrelevant CO2 reversal, in tonnes CO2e. See Risk of Reversal.

3.4.1 Emission allocation to reporting periods

Emissions that occur during a reporting period, [math: RP] are included directly and fully in that reporting period,protocol and are not allocated across multiple reporting periods.

When the project proponent is planning to cease operations within a given storage site, they must project the calculation of monitoring emissions required for post-closure monitoring, and allocate them to the remaining removals taking place at the storage site. If that is not possible, the project proponent should allocate those emissions to other projects and/or storage site they conduct removal operations at,repeated in agreementthis with Isometric. If for any reason emissions are not appropriately allocated, the Reversal process will be triggered in accordance with Isometric Standard, to account for any remaining monitoring emissions.

In instances where monitoring activites are shared between entities, for example if multiple DAC companies use the same storage infrastructure and share monitoring activities, the emissions associated with these activities must be allocated proportionally between the entities.

3.4.2 Calculation of CO2eEnergy, Monitoring

Emissions associated with CO2eEnergy, monitoring, are associated with electricity or fuel use, during reporting period [math: RP]. Examples of electricity usage for monitoring activities may include, but are not limited to:

• electricity used for monitoring equipment operation, including analyzers, instrumentation, on-site laboratories specifically for monitoring activities
• electricity used for sampling pumps, sampling systems, or other similar monitoring activities
• electricity used for off site analytical laboratory operation and sample analysis
• electricity used for monitoring system installation (if not accounted for in project embodied emissions) and operation, such as installation of monitoring wells, electricity used for temperature control of monitoring systems (heat trace)
• electricity for building operation & management for monitoring facility buildings

Examples of fuel consumption may include, but are not limited to:

• fuel used for sampling system operation, such as any pumps or heating systems
• fuel used for any handling equipment, such as fork trucks or loaders, which are used during sample collection and processing
• fuel used during monitoring system installation, operation or closure, such as that used by drill rigs

3.4.3 Calculation of CO2eTransportation, Monitoring

Emissions related to transportation associated with any monitoring activities during reporting period [math: RP], such as:

• transportation of samples for lab analysis
• transportation of specialty monitoring or sampling equipment to site

It should be noted that transportation emissions for monitoring will likely be zero or very low, as such emissions will typically be accounted for in fully burdened cradle-to-grave (​​Considering impacts at each stage of a product's life cycle, from the time natural resources are extracted from the ground and processed through each subsequent stage of manufacturing, transportation, product use, and ultimately, disposal.) emissions factors for equipment used in monitoring. Project proponents should use caution and ensure double counting (Improperly allocating the same Removal or Reduction from a Project Proponent more than once to multiple Buyers.) is not occurring between embodied emissions and transportation emissions accounted for here.

3.4.4 Calculation of CO2eEmbodied, Monitoring

Emissions related to equipment, materials, and supplies manufacture used during reporting period [math: RP] or amortized through allocation to a number of removals.

Examples of materials and equipment that must be considered as part of the embodied emission calculation include but are not limited to:

• non-feedstock (Raw material which is used for CO₂ Removal or GHG Reduction.) conversion process inputs or consumables:

  • gases, reagents or other materials used for operation of monitoring equipment, analytical testing, calibration of monitoring equipment and on-site analyzers
  • water
  • gasses such as nitrogen used for process or instrumentation purges
  • consumable sampling equipment or supplies that are used in significant quantities

• equipment:

  • monitoring wells and all associated materials (steel casing, concrete, etc.)
  • on-line analyzers, measurement equipment, or other such devices
  • pumps, piping, and related equipment installed for monitoring purposes
  • all related support structures and infrastructure, including steel platforms, framing, supports, etc. installed for monitoring purposes
  • buildings and associated equipment utilized for monitoring purposes(e.g., on-site laboratories)

Consumables such as those identified above will have embodied emissions associated with their production, use, transport, and disposal. Such emissions should be accounted for for any usage occurring during the reporting period and allocated to that reporting period only.

Equipment and materials which may be utilized over various reporting periods will have embodied emissions associated with their production, use, transport, and disposal. Such emissions should be accounted for over the life of the project and anticipated life of the equipment and allocated across all reporting periods during which the monitoring equipment is in use.

3.4.5 Calculation of CO2eMisc. monitoring

Miscellaneous GHG emissions for activities associated with monitoring for a given reporting period are those that cannot be categorized by [math: CO_{2}e_{Energy,\ Monitoring}], [math: CO_{2}e_{Transportation,\ Monitoring}], or [math: CO_{2}e_{Embodied,\ Monitoring}].

The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities and for reporting any outside of the categories provided as [math: CO_{2}e_{Misc.\ Monitoring}].

Examples of miscellaneous GHG emissions include but are not limited to:

• waste processing associated with monitoring
• staff travel associated with the project

3.4.6 Calculation of CO2eReversal

Calculation of CO2eReversal is included in Equation 1, but is covered seperately to the GHG assessment. See Risk of Reversal sectionmodule.

3.5 Closure Requirements

In order to decommission a site, the projectProject proponentProponent must prove beyond reasonable doubt that injected CO₂ will cause no harm to USDWs and stay within the target reservoir, thus demonstrating CO₂ storage will be durable for the expected >100,000-year timescales. The project proponent shall ensure that all the regulators permit requirements associated with planning for, preceding with and monitoring of well or site decommissioning are adhered to and documented.

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.

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

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

Within the EU, the site is transferred from the project proponent to a competent authority (i.e., national or local authorities) once 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 leakages or significant irregularities. This will be intensified if CO₂ leakages or significant irregularities are identified.

3.6 Recordkeeping

All records associated with the characterization, design, construction, injection operation, monitoring, and site closure shall be developed, submitted to proper authorities as required by the regulating permit.

All records shall be maintained for a minimum of 10 years after the well closure. All closure and post-closure monitoring records shall 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.

4.0 Acknowledgements

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

5.0 Definitions and Acronyms

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 increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities.

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.

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).

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.

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 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).

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).

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

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.

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, and reviewed EACs, based on Protocols. Registries Issue Certificates, and track their ownership and Retirement.

Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.

​​Considering impacts at each stage of a product's life cycle, from the time natural resources are extracted from the ground and processed through each subsequent stage of manufacturing, transportation, product use, and ultimately, disposal.

Improperly allocating the same Removal or Reduction from a Project Proponent more than once to multiple Buyers.

Raw material which is used for CO₂ Removal or GHG Reduction.

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

6.0 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 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.

7.0 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 Environmental Protection Agency. (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