CO₂ Storage in Saline Aquifers

1.0 Introduction

Durability refers to the length of time for which CO₂ is removed from the Earth’s atmosphere and therefore cannot contribute to further climate change. This moduleModule details durability and monitoring requirements for storage 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 (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., siliciclasticsiliclastic vs carbonate vs volcanogenic sandstones). To ensure sufficient durability, CO₂ characteristics and the conditions within the storage reservoir must be well defined, modeled 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) after closure (as per regulating permitting requirements) within the Area of Review (AOR)¹, the carbon dioxide can be considered geologically removed.

This moduleModule is applicable for gaseous, supercritical and water-dissolved CO₂ injections into saline aquifers within permeable sedimentary systems (such as siliciclasticsiliclastic 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 of 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)⁶². 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 events⁷⁶. This potential risk is likely lower within soft sedimentary basins⁸⁷. However, even small seismic events have the potential to damage the seal and create leakage⁹⁶.

• 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 formation¹⁰⁸. 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 from the geologic reservoir 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 projectProject is operating as permitted11. This plan should be submitted to the regulating authorities.

The subsurface monitoring approach developed and implemented by the Project Proponent 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 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 projectProject must comply with all applicable local environmental, ecological and social requirements as well as those set out in Section 5 of the DACrelevant 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+) 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 moduleModule, Project ProponentsProponents are required to follow either the U.S. EPA Underground Injection Control (UIC) or EU directives. All projectsProjects 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 projectProject Design Document (PDD document) upon submission to the relevant validation & verification body (VVB).

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 geophysicalthose surveys,set out in accordanceTable with1.

  Table 1.

  Parameter	Purpose
  Reservoir lithology and mineralogy	Input into reservoir models allowing for trapping mechanism predictions. Onsite characterization may include drilling, coring or logging.
  Porosity, permeability and volume of sequestration zone strata	Demonstrate the agreedcapacity monitoringand planinjectivity of the target formation to receive and safely store CO2
  Permeability and structural integrity of confining layer/cap rock	Demonstrate that any buoyant fluids or gasses will be trapped and unable to migrate upwards out of the reservoir.
  Temperature, pH, salinity/conductivity and fluid saturation of storage reservoir formation fluid/brine	For density calculations and inputs into reservoir models which will guide injection.
  Dissolved gas, including of DIC, composition in formation fluids and composition of any tracers being used (e.g., δ13C signature and/or major and minor ion).	To determine the trapping mechanisms that may occur and for leakage tracing, if required.
  Surface elevation models, where applicable, which account for natural variation over a year.	As a baseline for future measurements and allows inferences about pressure changes at depth.
  Surface/seafloor gas concentrations, where applicable	Measurements should be conductedtaken duringover sitea characterizationyear to act as a baseline spatial and temporal trends and variability for future measurements to determine if leaks are occurring.
  Baseline geophysical Surveys, where applicable.	A baseline characterisation 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 mustshould include  but is not limited:  to pH Temperature Dissolved, gastemperature, concentrations Conductivity Totaldensity, conductivity, total dissolved solids (TDS) Density and dissolved gas concentrations.	As a baseline for future measurements to determine if leaks are occurring.
  Baseline ecosystem imaging, where applicable.	As anda requiredbaseline byfor thefuture permitmeasurements to determine if leaks are occurring.

  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 projectProject 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 projectProject 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 projectProject must have sufficient structural strength and be designed for the life of the projectProject. All surface casing will be set below the lowermost USDW and cemented to the surface. All well materials must be compatible with fluids with which the materials may be expected to come into contact, including CO₂ and formation fluids (e.g., corrosion-resistant well casings and CO₂ resistant cement) and must meet or exceed standards developed for such materials by API, ASTM International, or comparable standards. The casing and cementing program must be designed to prevent the movement of fluids out of the 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. Where the jurisdiction issuing the permit has different monitoring requirements to those stated here, please provide justification of any deviation within the PDD. This plan should be updated every five years, unless the regulatory body that issues the permit requires this to be updated more often, to take account of changes to the assessed risk of leakage, changes to the assessed risks to the environment and human health, new scientific knowledge, and improvements in best available technology. The riskrisks (Section 1) addressed by each measurement will beare 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 temperatureTemperature
  • 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).
  • 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 shouldare 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.

• Wells must have gas detectors (or equivalent sensors/imaging) 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, and monitoring for a gaseous release (CO2CO₂, hydrocarbons or other GHGsGHGs). If activated the operator must immediately investigate and identify as expeditiously as possible (or in accordance with permit requirements) the cause of the alarm or shutoff, and report the instance to 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 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, iswhere required, must be completed 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). Satelliteor 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 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 images¹²⁹.

• 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^1310,1411.

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)USDWs [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 recomendedrecommended. 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 mineralisationmineralization)
  • 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 models¹⁵¹². 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 intergratedintegrated 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, iswhere required, should be completed 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 floor¹⁶¹⁰.
• pH monitoring using techniques such as using eddy covariance, pH sensors on remotely operated vehicles/Autonomousautonomous underwater vehicle, or water sampling¹⁷¹³.

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 dioxideCO₂ 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 models¹⁸¹². 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 projectProject proponentProponent and regulating body on a projectProject-specific basis using site-specific data from site characterization and injectate composition.

3.1.3.3 CO₂ leakage

If any CO₂ leakage is detected from the target reservoir or there are significant irregularities from the used model(s), the projectProject proponentProponent/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 projectProject proponentProponent 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 projectProject proponentProponent 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 2.7¹⁹¹⁴ 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 3.57 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 projectProject proponentProponent must follow any post-injection and site decommissioning requirements of the permit for the specified projectProject. 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 projectProject proponentProponent 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 projectProject proponenetProponent 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 the 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 projectProject proponentProponent 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 moduleModule.
  • 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 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 3.57.

3.3 Risk of reversalReversal

Based on present levels of scientific knowledge, projectsProjects applicable to this protocolModule 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 small¹⁰⁸. As a result, a 2% buffer pool will be set aside as a precaution. This reversal risk will be reassessed every 5 years, aligning with the creditingCrediting periodPeriod, or when new scientific research and knowledge are produced.

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

3.3.1 Attribution of reversalsReversals

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 emplacedinjected 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 reversals are determined to be a result of negligence by the Operator or Project Proponent, projectProject creditingCrediting may be ceased.

3.4 Calculation of CO₂e_Stored

[math: CO_2e_{Stored}] 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_{Stored,\ 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 reporting period, [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.

3.4.1 Measurement - CO₂e_Stored

Calculation of [math: CO_2e_{Stored}] 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.

3.4.2 CO₂ Concentration Measurements in CO₂ Streams

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

• Measured immediately upstream from the point of injection; and
  • Where CO₂ streams from multiple projects are injected into a single storage location, total CO₂ mass input from the project and of the total CO₂ stream to which it is injected may be measured at the location of transfer from the DAC facility into the combined stream. The weight fraction of CO₂ determined at this point may be used to calculate the CO₂ injected as measured immediately upstream from the injection point.
• Measured using a continuous inline analyzer for CO₂ concentration, such as NDIR, TDL, or similar, which satisfies the below requirements:
  • Must have an accuracy of 2% of full scale or better;
  • Recorded at a frequency of 1-minute intervals at minimum;
  • Must be calibrated in accordance with and at a frequency which meets or exceeds manufacturer calibration requirements, but which in any case must be no less than annual;
  • Calibration gasses must be traceable to national standards and a certificate of analysis indicating so; and
  • Raw data must be made available upon request.

3.4.3 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

3.4.4 Procedure for handling missing 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 reporting period, any missing data above this is also not creditable.

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

3.4.5 Required Records and Documentation - CO₂e_Stored

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

• Raw data provided via CO₂ stream meters (mass and concentration measurements) for the reporting period, [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.

3.5 Calculation of CO₂e_{Counterfactual}

Type: Counterfactual

The counterfactual for eligible projects is considered to be zero.

3.6 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 protocol and are not repeated in this moduleModule.

3.57 Closure Requirements

In order to decommission a site, the Project Proponent must prove beyond reasonable doubt that injected CO₂ will cause no harm to USDWs and stay within the target reservoir, thus demonstrating CO₂ storage will be durable for the expected >100,000-year timescales. The projectProject proponentProponent 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 projectProject proponentProponent 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 projectProject proponentProponent 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 projectProject proponentProponent notifies other stakeholders, such as nearby drinking water utilities and agencies with primacy for drinking water regulations. A copy of the site decommissioning plan should also be retained by the projectProject proponentProponent 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 projectProject proponentProponent 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 projectProject proponentProponent 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. If operating in other jurisdiction, the relevant regulations regarding liability must be followed and disclosed within the PDD.

3.68 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 projectProject proponentProponent 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 moduleModule.

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.

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.

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.

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.

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 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.

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).

Total Dissolved Solids.

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 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 databasedocument thatsubmitted holdsalongside information on VerifiedClaimed Removals and/or Reductions that details the calculations associated with a Removal or Reduction, including the Project's emissions, Removals, Reductions and reviewed EACsLeakages, basedpresented together in net metric tonnes of CO₂e per Removal or Reduction.

Purposefully erring on Protocolsthe 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. RegistriesThis Issueis Certificates,done andto trackincrease theirthe ownershiplikelihood andthat Retirementa given Removal or Reduction calculation is an underestimation rather than an overestimation.

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.

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.

Optoelectronic devices which measure temperature using optical fibres as sensors, providing a continuous temperature profile over kilometer distances.

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

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 Projectproject 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 creditingCredits.

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 AgencyEPA. (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