CO₂ Storage in Depleted Hydrocarbon Reservoirs

This Module details durability and monitoring requirements for storage of CO₂ removed from the atmosphere and stored in depleted hydrocarbon fields.

CO₂ can be injected into depleted hydrocarbon fields 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, composition and amount of hydrocarbons present and the type of reservoir the CO₂ is injected into (i.e., siliclastic 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 depleted hydrocarbon fields, injected CO₂ is prevented from vertically migrating by structural or stratigraphic barriers such as low permeability confining layer (i.e., 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 which 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), the CO₂ can be considered geologically sequestered.

This Module is applicable for gaseous, supercritical and water-dissolved CO₂ injections into depleted hydrocarbon fields within permeable sedimentary systems (such as siliclastic sandstones, carbonates and volcanogenic sandstones).

This section outlines requirements for evaluating CO₂ injection and storage within depleted hydrocarbon fields, 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 gases that may later be re-emitted (e.g., CO₂, CH₄). The injection site shall be monitored in accordance with this Module and 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 USDWs and demonstrates that the Project is operating as permitted. This plan should be submitted to Isometric.

The subsurface monitoring approach developed and implemented by the Project Proponent 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 act as baseline measurements against which to compare future monitoring. 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.

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

• Injected CO₂ plume migration out of the intended storage reservoir [risk A]. This risk is enhanced by mixing with residual hydrocarbons which can result in faster plume migration and potential leakage¹.

  • 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 dissolution 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 fault 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)². The seal integrity must be thoroughly characterized prior to injection and monitored throughout.
  • Induced microseismicity as large volumes of CO₂ are injected into brittle reservoirs within a few kilometers of the surface may trigger seismic events⁶. This potential risk is likely lower within soft sedimentary basins⁷. However, even small seismic events have the potential to damage the seal and cause leakage⁶.

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

  • CO₂ injection into depleted hydrocarbon fields 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. Hydrogen will likely be readily available within depleted hydrocarbon reservoirs and thus CH₄ may form ⁸. 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 gases from the geologic reservoir must be accounted for as detailed in Section 3.3.

• CO₂ Injection results in leakage in injection, monitoring or legacy wells [risk D].

  • CO₂ can damage integrity of any injection monitoring wells.
  • Residual hydrocarbons within reservoirs can be utilised by microbial communities leading to processes such as sulfidogenesis, microbiologically influenced corrosion (MIC) and biofouling during CO₂ injection ^{9, 10, 11, 12}.

The injection site must have a current well permit issued by the responsible authority for the location of the injection facility and reservoir. The permit must specifically identify CO₂ as acceptable injectants under the permit. In addition, the Project must comply with all applicable local environmental, ecological and social requirements as well as those set out in the relevant Protocol and Section 3.7 of the Isometric Standard. Reservoirs may not be utilized if enhanced hydrocarbon recovery (EHR or EHR+) activities are occurring within the field.

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

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

Site characterizations must include evaluation of reservoir chemistry (both rock and fluids) and conditions where required to ensure CO₂ will be stored within the reservoir. The permit shall define the 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 residual hydrocarbons or other fluids and injectant mobility and reservoir simulations will be required.

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

Table 1: List of baseline characterization requirements

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

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

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

A site visit must thereafter occur at least once every 2 years at each location.

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. This will help address risk D. Extra caution should be used on wells which penetrate the confining layers. Wells which pose a risk to durability must be plugged prior to injection in order to:

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

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

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

• Maximum allowable surface injection pressure (MASIP) at the injection wellhead that is allowed during injection operations to prevent fracturing of the formation, set according to the regulators permit. Injection operation pressures 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 3.4.

• Analysis of the CO₂ with sufficient frequency to yield data representative of its chemical and physical characteristics, using industry standard or indicated methods and quality and properly calibrated equipment [C]:

  • Temperature
  • CO₂ concentration as described within Section 3.4.
  • 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 injection)
  • Viscosity (for dissolved/ supercritical injection)
  • If dissolved CO₂ is being injected, it is recommended that major & minor ions and δ¹⁸O, δD are also be measured

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

• 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 (CO₂, hydrocarbons or other GHGs). 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 Isometric.

• Corrosion monitoring must be performed and reported quarterly. This includes identifying any loss of mass and/or thickness, cracking, pitting, or other signs of corrosion, to ensure that well components meet the minimum standards for material strength and performance set by API, ASTM International, or equivalent. In addition, any monitoring wells should also be monitored for their internal integrity [A, D].
• A demonstration of external mechanical integrity annually from prior to injection until the injection well is plugged. This could include but is not limited to: an oxygen activation log, temperature log or sensors (e.g., distributed temperature sensors), or noise log. If one test indicates the potential loss of mechanical integrity, follow-up tests can verify and further characterize the potential leakage pathway [A, D].
• A pressure fall-off test every 2 years [A, D].
• Screening to ensure that injection, chemical treatments and metallurgy specifications are evaluated as part of a comprehensive microbial risk framework for biofouling, souring and microbial indcued corrosion, mitigating potential impacts on system integrity and performance [D].

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.

Surface monitoring, where required by permit, should be completed at site-specific frequency and spatial distribution determined by the permitting regime 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) or satellite interferometry (InSAR). Been previously used to measure small displacements of the ground surface (of up to 2–3 cm) that have been related to the injection of CO₂ at depth.
  • Surface- and subsurface-based tiltmeters.
  • GPS instruments.

• Ecosystem stress, 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 images¹³.

• 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 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 gases, 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^{14, 15}

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

• Geochemical monitoring of USDWs may be required periodically (as agreed in the monitoring plan with the regulating authority) for groundwater quality and geochemical changes that may result from carbon dioxide or 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 gases) and any other constituents identified by the owner or operator and/or the regulators.

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 (direct); (2) geophysical monitoring (indirect); (3) groundwater geochemical monitoring (direct); and (4) computational modeling (indirect). Monitoring should include both direct and indirect monitoring [A,B,C].

• Indirect methods should include reservoir imaging (e.g., seismic, gravity and/or electrical methods) which should be chosen based on their response to predictions in reservoir & geological models and storage simulations, and compared against the baseline conditions. This will be required to track the presence or absence of elevated pressure within the injection zone and the extent of the carbon dioxide plume, unless the regulator determines that such methods are not appropriate. Indirect monitoring of plume migration should be conducted every 5 years. If not appropriate additional direct monitoring may be required.

• Direct methods should include continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) to show vertical containment within the storage reservoir. Temperature and pressure should be logged continuously, for example temperature could be measured through a fiber-optic distributed temperature sensing system. Pressure monitoring in the zone immediately above the sealing interval is also required. A pressure fall-off test should be conducted every 2 years to assess reservoir injectivity.

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

• Reservoir modeling must be performed, including pressure and fracture simulations. This could be either using traditional reservoir models or CCSNET models¹⁶. The model should be compared to data directly collected from the reservoir (e.g., pressure, temperature) and any other nearby relevant subsurface data (i.e., porosity and permeability of our injection horizon and confining layer, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment of CO₂ within targeted injection zone. Reservoir models must be updated as operational data changes [A,B,C].

• Monitoring of wellhead pressure continuously and the composition of any gas recovered from well(s) or representative sampling locations where detection of gases 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. Wellhead gas sampling frequency should be monthly [B,C].

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

Surface monitoring, where required by permit, should be completed at site-specific frequency and spatial distribution determined by the permitting regime 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 gases, 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 floor¹⁴.

• pH monitoring using techniques such as using eddy covariance, pH sensors on remotely operated vehicles/autonomous underwater vehicle, or water sampling¹⁷.

• 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 CO₂ plume and area of elevated pressure. Available methods for plume and pressure-front tracking include: (1) fluid pressure and temperature monitoring (direct); (2) geophysical monitoring (indirect); and (3) computational modeling (indirect). Monitoring should include both direct and indirect monitoring [A,B,C].

  • Indirect methods should include reservoir imaging (e.g., seismic, gravity and/or electrical methods) which should be chosen based on their response to predictions in reservoir & geological models and storage simulations, and compared against the baseline conditions. This will be required to track the presence or absence of elevated pressure within the injection zone and the extent of the CO₂ plume, unless the regulator determines that such methods are not appropriate. Indirect monitoring of plume migration should be conducted every 5 years. If not appropriate additional direct monitoring may be required.
  • Direct methods should include continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) to show vertical containment within the storage reservoir. Pressure monitoring in the zone immediately above the sealing interval is also required. A pressure fall-off test should be conducted every 2 years to assess reservoir injectivity.

• Reservoir modeling must be performed, including pressure and fracture simulations. This could be either using traditional reservoir models or CCSNET models¹⁶. The model should be compared to data directly collected from the reservoir (e.g., pressure, temperature) and any other nearby relevant subsurface data (i.e., porosity and permeability of our injection horizon and confining layer, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment of CO₂ within targeted injection zone. Reservoir models must be updated as operational data changes [A,B,C].

• Monitoring of the wellhead pressure continuously and composition of any gas recovered from well(s) or representative sampling locations where detection of gases 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. Wellhead gas sampling frequency should be monthly [B,C].

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

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

The Project Proponent/Operator must prepare an emergency response plan which outlines corrective actions which will be taken in case of CO₂ leakage. The plan must be submitted and approved by the component permitting authority. 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 emergency response plan and approved by the competent authority. For a loss of conformance with models, the Project Proponent must halt injection whilst they identify the cause of this loss, and then revise the monitoring plan to account for this change of migration. If there is a leak the Project Proponent must halt injection whilst they conduct an assessment to determine if the loss of containment can be repaired prior to injection beginning again. The amount of CO₂ lost must also be quantified and subtracted from the overall total of CO₂ 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 2.7¹⁸ 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.

The aim of this post-injection monitoring and the closure requirements in Section 3.7 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 CO₂ removals. The Project Proponent must follow any post-injection and site decommissioning requirements of the permit for the specified Project. Post-injection is defined as monitoring between the end of injection and plugging of the wells. Once injection has ceased (e.g., this is defined as closure in the EU) the site must undergo post-injection monitoring. Once it is demonstrated that the injected 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 Proponent must follow guidance from the regulating authority.

Post-injection monitoring should apply the same monitoring strategy as implemented during injection and operation, with a focus on methods tailored to address the anticipated system changes and risks that may occur. Post-injection monitoring must be carried out in accordance with the local permitting regime (for approved permits) or the certified monitoring plan (for other jurisdictions). This monitoring must include reservoir modeling alongside indirect seismic imaging and direct measurements from the injection well of temperature and pressure to trace plume migration and the pressure front. Corrosion monitoring and external mechanical integrity testing must be conducted annually for the first three years after injection. A pressure fall-off test must initially be conducted every two years. It is recommended that USDWs be monitored to identify and address any leakage pathways that arise. Any measured parameters should be compared to modeled predictions to help refine the model or identify possible risks. The frequency of post-injection monitoring may be reduced, determined by specific, risk-based, quantitative criteria detailed as part of the regulating permit or approved montiroing plan. Such criteria could include the reservoir pressure reaching a certain level relative to pre-injection conditions or steady or favorable trends in observed geochemical monitoring results over a predefined period, and agreement with model predictions.

After a minimum of 15 years (USA) or 20 years (EU) or equivalent, an assessment must be completed to demonstrate plume stabilization or a trend towards stabilization. Reassessments 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 time frame for pressure decline within the injection zone.
• Utilize predictive modeling, where deemed appropriate by Isometric and/or the regulating body and/or the certified geologist who approved the monitoring plan, based on monitoring data collected during post-injection monitoring to demonstrate the stability of the CO₂ plume and lack of plume migration in the formation that would present a risk to water sources in the AOR.
  • Modeling must be validated by comparison to historical monitoring data including subsurface pressure and plume migration.
  • Models must utilize site specific geochemistry and CO₂ characteristics from analyses required in Section 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.
• By new methods as outlined in subsequent Protocol versions and as measurement and monitoring technologies advance.

The time frame 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 time frame, 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 Certified Professional Geologist (i.e. Chartered Geologist or equivalent), the CO₂ plume will be considered stabilized and the site decommissioned following requirements in Section 3.7.

The reversal risk shall be determined on a project by project basis. 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 small⁸. 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 as detailed in Section 5.6 of the Isometric Standard.

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

1. If the Project Proponent was the only entity injecting into a given reservoir, the Project Proponent will take on 100% of the reversal.

2. If the Project Proponent was one of multiple entities injecting into that reservoir, the Project Proponent will be allocated a percentage of the reversed CO₂ proportional to the mass of injected material. For example:

   • A reservoir has a total of 200t of material injected at the time when the reversal is detected (this information 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, project crediting may be ceased.

$CO_2e_{Stored}$ 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 $RP$. This is the gross mass stored and does not account for reversals of storage from the storage formation.

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

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

(Equation 1)

Where:

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

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

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

(Equation 2)

Where:

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

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

Calculation of $CO_2e_{Stored}$ requires two primary measurements

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

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 gases must be traceable to national standards and indicated by a certificate of analysis
  • Raw data must be made available upon request

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

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

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

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

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

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

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

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, $RP$
• 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
  • 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
• 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.

Type: Counterfactual

The counterfactual for eligible projects is considered to be zero.

Type: Emissions

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

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

In order to decommission a site, the Project Proponent must prove beyond reasonable doubt that injected CO₂ will cause no harm to USDWs and stay within the 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, 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. The monitoring rate will be increased 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.

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 made available to interested parties for review upon request or if concerns are raised.

Rebecca Tyne, Ph.D.

Nicholas Ashmore, Ph.D.

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

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

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

Table A.1 Pre-Injection Monitoring Requirements

Table A.2 Operational Monitoring Requirements

Table A.3 Post-Injection Monitoring Requirements

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

Current approved regulatoring permits:

• U.S. EPA Underground Injection Control (UIC)¹⁹
• EU directive ²⁰
• Alberta directive ^{21 22}

1. Ghanbari, S., Mackay E.J., Heinemannn N., Alcalde J., James, A., Allen, M.J. (2020). Impact of CO₂ mixing with trapped hydrocarbons on CO₂ storage capacity and security: A case study from the Captain aquifer (North Sea). Applied Energy, 278, 115634. https://doi.org/10.1016/j.apenergy.2020.115634 ↩

2. Kaldi, J., Daniel, R., Tenthorey, E., Michael, K., Schacht, U., Nicol, A., Underschultz, J. and Backe, G. (2013). Containment of CO₂ in CCS: Role of caprocks and faults. Energy Procedia, 37, 5403–5410. https://doi.org/10.1016/j.egypro.2013.06.458 ↩ ↩²

3. Jha, B. and Juanes, R. (2014). Coupled multiphase flow and poromechanics: A computational model of pore pressure effects on fault slip and earthquake triggering. Water Resources Research, 50, 3776–3909. https://doi.org/10.1002/2013WR015175 ↩

4. Rinaldi, A. P., Rutqvist, J. and Cappa, F. (2014). Geomechanical effects on CO₂ leakage through fault zones during large-scale underground injection. International Journal of Greenhouse Gas Control, 20, 117–131. https://doi.org/10.1016/j.ijggc.2013.11.001 ↩

5. Vilarrasa, V., Makhnenko, R. Y. and Lyesse Laloui. (2017). Potential for fault reactivation due to CO₂ injection in a semi-closed saline aquifer. Energy Procedia, 114, 3282–3290. https://doi.org/10.1016/j.egypro.2017.03.1460 ↩

6. Zoback, M. D. and Gorelick, S. M. (2012). Earthquake triggering and large-scale geologic storage of carbon dioxide. Proceedings of the National Academy of Sciences, 109, 10164–10168. https://doi.org/10.1073/pnas.1202473109 ↩ ↩²

7. Vilarrasa, V. and Carrera, J. (2015). Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO₂ could leak. Proceedings of the National Academy of Sciences, 112, 5938–5943. https://doi.org/10.1073/pnas.1413284112 ↩

8. Tyne, R. L., Barry, P. H., Lawson, M., lloyd, K. G., Giovannelli, D., Summers, Z. M., and Ballentine, C. J. (2023). Identifying and Understanding Microbial Methanogenesis in CO₂ Storage. Environmental Science & Technology, 57, 9459–9473. https://doi.org/10.1021/acs.est.2c08652 ↩ ↩²

9. Jones, D. M., I. M. Head, N. D. Gray, J. J. Adams, A. K. Rowan, C. M. Aitken, B. Bennett, H. Huang, A. Brown, B. F. J. Bowler, T. Oldenburg, M. Erdmann and S. R. Larter (2008). Crude-oil biodegradation via methanogenesis in subsurface petroleum reservoirs. Nature, 451(7175): 176-180. ↩

10. Gieg, L. M., T. R. Jack and J. M. Foght (2011). Biological souring and mitigation in oil reservoirs. Appl Microbiol Biotechnol, 92(2): 263-282. ↩

11. Skovhus, T. L., R. B. Eckert and E. Rodrigues (2017). Management and control of microbiologically influenced corrosion (MIC) in the oil and gas industry-Overview and a North Sea case study. J Biotechnol, 256: 31-45. ↩

12. Scheffer, G., C. R. J. Hubert, D. R. Enning, S. Lahme, J. Mand and J. R. de Rezende (2021). Metagenomic Investigation of a Low Diversity, High Salinity Offshore Oil Reservoir. Microorganisms, 9(11). ↩

13. Chen, Y., Guerschman, J. P., Cheng, Z., and Guo, L. (2019). Remote sensing for vegetation monitoring in carbon capture storage regions: A review. Applied Energy, 240, 312–326. https://doi.org/10.1016/j.apenergy.2019.02.027 ↩

14. Flohr, A., Matter, J. M., James, R. H., Saw, K., Brown, R., Gros, J., Flude, S., Day, C., Peel, K., Connelly, D., Pearce, C. R., Strong, J. A., Lichtschlag, A., Hillegonds, D. J., Ballentine, C. J., and Tyne, R. L. (2021). Utility of natural and artificial geochemical tracers for leakage monitoring and quantification during an offshore controlled CO₂ release experiment. International Journal of Greenhouse Gas Control, 111, 103421. https://doi.org/10.1016/j.ijggc.2021.103421 ↩ ↩²

15. Weber, U. W., Kampman, N., and Sundal, A. (2021). Techno-economic aspects of noble gases as monitoring tracers. Energies, 14, 3433. https://doi.org/10.3390/en14123433 ↩

16. Wen, G. and Benson, S. M. CCSNet, a deep learning modeling suite for CO₂ storage. https://ccsnet.ai/ ↩ ↩²

17. Flohr, A., Schaap, A., Achterberg, E. P., Alendal, G., Arundell, M., Berndt, C., Blackford, J., Böttner, C., Borisov, S. M., Brown, R., Bull, J. M., Carter, L., Chen, B., Dale, A. W., de Beer, D., Dean, M., Deusner, C., Dewar, M., Durden, J. M., Elsen, S., Esposito, M., Faggetter, M., Fischer, J. P., Gana, A., Gros, J., Haeckel, M., Hanz, R., Holtappels, M., Hosking, B., Huvenne, V. A. I., James, R. H., Koopmans, D., Kossel, E., Leighton, T. G., Li, J., Lichtschlag, A., Linke, P., Loucaides, S., Martínez-Cabanas, M., Matter, J. M., Mesher, T., Monk, S., Mowlem, M., Oleynik, A., Papadimitriou, S., Paxton, D., Pearce, C. R., Peel, K., Roche, B., Ruhl, H. A., Saleem, U., Sands, C., Saw, K., Schmidt, M., Sommer, S., Strong, J. A., Triest, J., Ungerböck, B., Walk, J., White, P., Widdicombe, S., Wilson, R. E., Wright, H., Wyatt, J., and Connelly, D. (2021). Towards improved monitoring of offshore carbon storage: A real-world field experiment detecting a controlled sub-seafloor CO₂ release. International Journal of Greenhouse Gas Control, 106, 103237. https://doi.org/10.1016/j.ijggc.2020.103237 ↩

18. Cal. Code Regs., tit. 14, § 1724.14 (2017). Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations. Not accessible in the EU, copy available on request. https://www.conservation.ca.gov/index/Documents/04-26-17%20UIC%20Pre-Rulemaking%20DD%20V.2%20%28tracking%20changes%20from%20DD%20V.1%29%204-25-17.pdf ↩

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

20. 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 ↩

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

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