CRCF Subsurface Storage

This Module is is developed for issuing Credits under the EU Carbon Removal and Carbon Farming (CRCF) framework established by EU Regulation 2024/3012. This Module incorporates and builds upon requirements from the following EU regulatory and guidance frameworks for geological CO₂ storage:

• Directive 2009/31/EC (the CCS Directive)
• CCS Directive Guidance Documents (GD1–GD4, revised July 2024)
• Commission Implementing Regulation (EU) 2018/2066 (the ETS Monitoring and Reporting Regulation, MRR)
• The CRCF Delegated Act Annex methodologies

This Module contains the relevant additional Isometric requirements from our CO₂ storage in Depleted Hydrocarbon Reservoirs Module and our CO₂ storage in Saline Aquifers Module. Where requirements are entirely satisfied by the CCS Directive, its Guidance Documents, the MRR, or the CRCF Delegated Act Annex methodologies, they are omitted. Where requirements are partially satisfied by these frameworks, they have been reformulated to build on the existing regulatory baseline.

This Module is applicable for gaseous, supercritical and water-dissolved CO₂ injections into saline aquifers and depleted hydrocarbon fields within sedimentary systems (such as siliclastic sandstones, carbonates and volcanogenic sandstones). CO₂ storage in unmineable coal beds is not permitted.

The injection site shall have a current well permit issued under EU Directive 2009/31/EC or under national legislation transposing the Directive. In addition, the injection site shall comply with all applicable local environmental, ecological and social requirements.

Isometric treats a valid CCS Directive permit as evidence that the regulatory requirements for site selection, characterization, and operational planning have been met. To demonstrate this, the Operator shall provide the Certification Scheme and the Certification Body with:

1. The storage permit number and the permit application or a summary of the approved storage permit, including any conditions attached by the competent authority.
2. Copies of periodic operator reports submitted to the competent authority under Article 14 of the CCS Directive, on an ongoing basis.
3. Copies of any competent authority responses, inspection reports, or enforcement actions relating to the storage site.

Where monitoring parameters in this Module defer to the permit, the permit requirements shall be detailed within the Activity Plan and followed throughout the Activity. Where a requirement does not allow permit compliance as evidence, the required evidence shall be submitted separately.

Any deviations from the relevant EU regulations and this Module shall be outlined within the Activity Plan upon submission to the Certification Body.

Monitoring requirements that form part of the CCS Directive permit requirements may be satisfied through the submissions to the competent authority under the storage permit.

The Operator shall maintain copies of all data and evidence submitted to the permitting authority against these requirements and shall provide such records to the Certification Scheme and the Certification Body within 30 days of submission to the permitting authority, or upon request.

Site characterization shall be completed in alignment with Annex 1 of the EU Directive 2009/31/EC and the CCS Directive Guidance Document 1 (GD1) and Guidance Document 2 (GD2). Specifically, the site characterization shall follow Step 1 to Step 3 set out in Annex 1, and the requirements in Article 4, Article 3, Article 11(3), GD1 and GD2 covering:

• Data collection and geological assessment, including reservoir lithology, mineralogy, porosity, permeability, sequestration zone volume, caprock integrity, temperature, pH, salinity, and fluid saturation (GD2 Sections 3.3–3.4).
• Storage capacity assessment and injectivity evaluation (GD2 Section 3.2).
• 3D geological modelling and dynamic behaviour characterization, including reservoir simulations and coupled process modelling (GD2 Section 3.5, Table 2).
• Long-term stability and demonstration of limited lateral migration (GD1 Section 4.1; GD2 Section 3.5; GD3 Section 4.1.3).
• Confining system assessment for transmissive faults and fractures, and leakage pathway analysis (GD1 Section 4.3.2, Table 5; GD2 Section 3.4, Box 1).
• Seismicity assessment, including evaluation of natural, induced and triggered seismicity (GD2 Section 3.3.6).
• Injection pressure limits, based on minimum total principal stress (GD2 Section 3.3.5).
• Definition of the storage complex and surrounding area (GD1 Section 2.4).
• Review frequency and coverage of site characterization and analytical modelling (Article 11(3)(e)).

Isometric recommends the following as additional guidance for baseline characterization:

• 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.
• For depleted hydrocarbon reservoir projects, assessment of potential interactions between injected CO₂ and residual hydrocarbons is also recommended, including effects on injectivity, containment, and trapping mechanisms.

In addition, baseline characterization shall be conducted in accordance with GD2 Sections 3.3–3.4 and Section 5.2.2.4. Table 1 lists additional baseline parameters and considerations recommended by Isometric as guidance.

Table 1: List of Isometric additional guidance for baseline characterization

Well construction shall comply with the requirements of the storage permit issued under EU Directive 2009/31/EC. The CCS Directive requires assessment of wells as potential leakage pathways (Annex I), and the Guidance Document 1, 2, 3 and 4 provide further detail on well evaluation and integrity covering:

• All wells within the storage complex, including injection, observation, monitoring, legacy and production wells, shall be evaluated for barrier integrity in accordance with GD2 Section 3.3.7, including assessment of materials, number, length and position of barriers. GD1 Section 2.4 requires that the storage complex definition includes all legacy wells with potential leakage pathways.
• Wells that pose a risk to containment shall be sealed prior to injection, using appropriate materials and methods that account for geochemical reactions and geomechanical effects on material integrity (GD2 Section 3.3.7; GD3 Section 4.4). GD2 recommends two independent barriers; a single barrier is acceptable where the risk assessment demonstrates insignificant risk.
• Well design shall follow industry best practice as recommended by GD2 Section 5.2.1, accounting for the acidic nature of CO₂ in the presence of water. GD3 Section 4.4 references ISO 27914:2017 and DNV RP-J203 for well decommissioning standards.

Isometric recommends the following as best-practice guidances for well construction and integrity:

• Casing, cement, tubing, packer, wellhead, valves, piping and other materials used in well construction should have sufficient structural strength and be designed for the life of the project.
• All well materials should be compatible with fluids with which the materials may be expected to come into contact, including CO₂, groundwater and/or formation fluids (e.g., corrosion-resistant well casings and CO₂-resistant cement).
• Well materials should meet or exceed standards developed by ISO, DNV, API, ASTM International, or comparable bodies as appropriate to the jurisdiction.
• The casing and cementing program should be designed to prevent the movement of fluids out of the storage formation and into groundwater or other protected formations.

Monitoring of injection, system integrity, subsurface migration, and post-closure shall be consistent with the monitoring framework established by EU Directive 2009/31/EC and the Monitoring and Reporting Regulation (Implementing Regulation 2018/2066). Specifically, the following requirements are applicable:

CCS Directive: Article 9 (permit conditions including operational pressure limits), Article 12 (CO₂ stream acceptance criteria and monitoring obligations), Article 13 (monitoring plan and five-year update cycle), Article 14 (annual reporting), Article 16 (corrective measures), Article 17 (post-injection obligations), Article 18 (transfer of responsibility), Annex I (site characterization criteria informing monitoring design), and Annex II (mandatory monitoring parameters covering injection wellhead pressure, temperature and flow, chemical analysis of injected material, reservoir conditions, fugitive emissions, CO₂ plume distribution, and comparison of observed versus predicted behaviour).

CCS Directive Guidance Documents: GD2 Sections 3.3.5–3.3.6 (injection pressure limits and seismicity monitoring), GD2 Sections 4.2–4.4 (CO₂ stream composition and impurities assessment), GD2 Section 5 (monitoring methodology, well integrity monitoring, baseline surveys, reporting, and post-closure monitoring), GD2 Section 6 (corrective measures framework), and GD3 (transfer of responsibility criteria including the 20-year minimum assessment period, long-term stability indicators, and well sealing requirements).

Monitoring and Reporting Regulation (MRR): Articles 40–49 and Annex IV Sections 22–23, covering the binding quantification methodology for CO₂ transport and geological storage, quality assurance standards (Article 42, referencing EN 14181 and EN ISO 16911-2), the annual emissions calculation methodology (Article 43), missing data procedures (Article 45), measurement-based methodology for transferred CO₂ (Article 49), and leakage quantification requirements.

Where the above provisions fully address a monitoring requirement, they are not repeated in this Module. The following subsections set out additional Isometric guidance for monitoring where the EU framework is non-prescriptive on specific methodologies, instruments, frequencies, or thresholds.

Isometric recommends the following as additional best practice guidances for injection and injectant monitoring:

• CO₂ concentration should be measured using continuous inline analysers (e.g. NDIR or TDL), at ≤2% accuracy and 1-minute intervals, with annual calibration. For dissolved CO₂ injection, pH should also be measured; for dissolved or supercritical injection, viscosity should be measured. Where dissolved CO₂ is being injected, measurement of major and minor ions, δ¹⁸O and δD is also recommended.
• Mass flow should be measured using Coriolis or thermal mass flow meters, at ≤2% accuracy, with annual calibration.
• Wells should have gas detectors (or equivalent sensors/imaging) with alarms and injection shut-off systems, including at a minimum injection pump shutoff when maximum pressure is reached or maximum flow rate is exceeded, and monitoring for gaseous release (CO₂, hydrocarbons or other GHGs). If activated, the operator should immediately investigate the cause and report the instance to the Certification Scheme.

Isometric recommends the following as additional best practice guidances for system integrity monitoring:

• Internal mechanical integrity testing every 6 months, including identifying any loss of mass and/or thickness, cracking, pitting, or other signs of corrosion, to ensure well components meet minimum standards for material strength and performance set by ISO, DNV, API, ASTM International, or equivalent. Monitoring wells should also be assessed for internal integrity.
• External mechanical integrity testing annually, from prior to injection until the injection well is plugged. Methods may include oxygen activation logs, temperature logs or sensors (e.g. distributed temperature sensors), or noise logs. If one test indicates potential loss of mechanical integrity, follow-up tests should verify and further characterizes the potential leakage pathway.
• A pressure fall-off test every 2 years.
• Corrosion monitoring quarterly, including assessment of mass loss, cracking and pitting.
• Assessment of microbial risks, including biofouling, reservoir souring, and microbiologically influenced corrosion (MIC), where site conditions warrant.

Isometric recommends the following as best practice guidances for onshore surface monitoring:

• Surface displacement could 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 leaks. 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 images.
• Surface CO₂ density and flux measurements 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.

Isometric recommends the following as best practice guidances for onshore near surface monitoring:

• Geochemical monitoring of groundwater 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 groundwater 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.

Isometric recommends the following as best practice guidances for onshore subsurface monitoring:

• Reservoir imaging (seismic, gravity, and/or electrical methods) as indirect monitoring. Methods could be chosen based on site-specific reservoir models and compared to baseline conditions. Imaging shall be conducted every 5 years unless the regulator determines alternative monitoring is more appropriate.

• For direct monitoring: continuous measurements of reservoir temperature and pressure (e.g. fibre-optic distributed temperature sensing) to show vertical containment within the storage reservoir. Pressure and temperature monitoring in the zone immediately above the sealing interval is also recommended. Periodic measurement of formation water density, to determine the likelihood of clogging, is also recommended.

• Where indirect monitoring is not appropriate or there may be risks associated with the dissolved-phase plume, geochemical monitoring may be used to track plume extent and CO₂ behaviour in the subsurface. 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)
  • Density

• Pressure fall-off testing every 2 years is recommended

• Monthly monitoring of wellhead gas composition at ≥0.01 vol% resolution and compared to baseline values obtained prior to injection is recommended

• In areas of increased seismicity risk, a seismic monitoring program including deeper wireline or cemented subsurface geophones for microseismic monitoring is recommended. Seismic events of magnitude 2.7 or greater within the storage complex should trigger re-evaluation of operations and containment.

Isometric recommends the following as best practice guidances for offshore surface monitoring:

• CO₂ density and flux measurements at the sea floor, using 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 CO₂ leaks at the ocean floor.
• pH monitoring using techniques such as using eddy covariance, pH sensors on remotely operated vehicles/autonomous underwater vehicle, or water sampling.

Subsurface monitoring requirements for offshore storage are consistent with onshore requirements (Section 3.2.1.3). Isometric recommended guidance for subsurface monitoring methods set out in Section 3.1.3 applies equally to offshore sites.

Isometric recommends the following as best practice guidances for addressing fugitive CO₂ leaks:

In the event fugitive CO₂ leaks from the reservoir is detected, Storage Operators is recommended:

• Halt injection while identifying the cause of any loss of conformance with models or containment breach
• Conduct assessment to determine if loss of containment can be repaired prior to resuming injection

Re-evaluation of CO₂ plume is recommended when warranted based on observational or quantitative changes, including but not limited to:

• Observed migration of CO₂ plume outside the target formation or into caprock/zones above target formation
• Actual CO₂ plume or elevated pressure extend beyond analytical model expectations due to:
  • An earthquake of magnitude 2.7 or greater within the AOR

Post-injection monitoring, post-closure planning, and transfer of responsibility shall follow the requirements of the EU Directive 2009/31/EC, Guidance Document 3 (GD3) and Guidance Document 2 (GD2). The operator is responsible for all monitoring obligations until transfer of responsibility to the competent authority (Article 17(2)), including preparation of a post-closure plan (Article 17(3), Article 7(8), Article 9(7); GD3 Section 4.3) and demonstration that stored CO₂ is completely and permanently contained (Article 18(1)(a)). GD3 defines the criteria for transfer: conformity of actual behaviour with modelled behaviour, absence of detectable leakage for a minimum of ten years (GD3 Section 4.1.2), static geological model stability for a minimum of five years (GD3 Section 4.1.1), and evolution towards long-term stability as indicated by pressure trends, plume extent, and well material condition (GD3 Section 4.1.3). A minimum 20-year post-closure monitoring period applies (Article 18(1)(b)), and monitoring methods and intensity may be adjusted based on risk as the site evolves (GD2 Section 5.4).

Isometric recommends the following as additional best practice guidances for post-injection monitoring:

• External mechanical integrity testing of monitoring and injection wells annually for the first three years after injection ceases, and every five years until site decommissioning, to ensure wells do not become leakage pathways.
• Corrosion monitoring annually for the first three years post-closure.
• Plume stabilisation assessment methods should include one or more of the following:
  • Geophysical monitoring of the CO₂ plume to demonstrate limited change since cessation of injection.
  • Predicted timeframe for pressure decline within the injection zone.
  • Predictive modelling, validated by comparison to historical monitoring data including subsurface pressure and plume migration, utilising site-specific geochemistry and CO₂ characteristics. Models should assess potential plume extent after 50 years and demonstrate that the plume will not migrate beyond the target reservoir or impact drinking water sources.
  • Tracer studies to demonstrate lack of vertical migration outside the authorised injection zone, where conditions and existing monitoring wells allow.
• Plume stabilisation should be independently reviewed and certified by a registered Professional Geologist (i.e. Chartered Geologist or equivalent) before the site is decommissioned.

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. For depleted hydrocarbon reservoirs, there is a very small risk of methane production within the reservoir, based on current literature. This reversal risk will be reassessed at every Activity Period, or when new scientific research and knowledge are produced.

In instances where reversals are determined to be a result of negligence by the storage operator, Activity Crediting may be ceased. Reversals will be accounted for by Operators and the Isometric Registry as detailed in Section 5.6 of the Isometric Standard.

The EU Directive 2009/31/EC requires operators to monitor volumetric flow, pressure, and temperature at injection wellheads (Annex II 1.1(f)(g)), chemical analysis of the injected CO₂ stream (Annex II 1.1(h)), and to report quantities and composition of CO₂ streams injected (Article 14). The Monitoring and Reporting Regulation (Implementing Regulation 2018/2066) requires measurement-based methodology for transferred CO₂ (Articles 40 and 49) and quality assurance in accordance with EN 14181.

The following sets out Isometric's guidance for calculating CO₂ injected for the purpose of credit issuance.

${CO_2}_{injected,S}$ is used in Equation 34 in the CRCF Protocol and represents the amount of CO₂ present in the CO₂-containing injectant that is injected and stored in the geologic or engineered storage site in a given Certification Period.

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 Certification Period:

$${CO_2}_{injected,S} = \sum_{t=1}^{T}  C_{mean, inj,t} \cdot m_{inj,t}$$

(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 $T$.
• $T$ = ${Certification Period}/Δt$, the number of time units in the Certification Period.
• $Δt$ = 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 shall be provided at the point of Re-certification Audit.

Calculation of ${CO_2}_{injected,S}$ 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.

Chemical analysis of the injected CO₂ stream is required under Annex II 1.1(h) of the EU Directive 2009/31/EC. Quality assurance of continuous measurement systems shall be consistent with EN 14181 (MRR Article 42).

Isometric recommends measuring the concentration of CO₂ in the gaseous, dissolved or supercritical CO₂ stream using a continuous inline analyser (e.g. NDIR, TDL, or similar) and note the following:

• Accuracy of 2% of full scale or better
• Recorded at a frequency of 1-minute intervals at minimum
• Calibrated no less than annually, meeting or exceeding manufacturer requirements
• Calibration gases traceable to national standards and indicated by a certificate of analysis
• Raw data made available upon request

Flow measurement shall be consistent with the MRR quality assurance requirements (Article 42), including EN ISO 16911-2 for flow measurement and EN ISO/IEC 17025 for laboratory accreditation.

Isometric recommends the following additional specifications:

• Preference for high-accuracy flow meters such as Coriolis or thermal mass flow meters
• Meter accuracy of 2% full scale
• Calibrated no less than annually, traceable to national standards
• Factory calibration for the specific gas composition range expected
• Selected and installed for the expected operating range, in accordance with manufacturer installation guidelines
• Raw data made available upon request

Site closure, transfer of responsibility, and post-transfer monitoring shall follow the requirements of the EU Directive 2009/31/EC (Articles 17–18, Article 12, Article 4, Article 26) and Guidance document 3.

Isometric recommends the following as additional best practice guidance for closure:

• During decommissioning, flushing of all wells with a buffer fluid, determination of bottom hole reservoir pressure, and a final external mechanical integrity test should be performed to ensure that plugging materials and procedures are selected correctly.
• CO₂ storage agreements with pore space owners should ensure activity in the storage site is prohibited in perpetuity following CO₂ injection, to prevent pressure disturbances in the storage reservoir.
• The Operator should notify other stakeholders, such as nearby drinking water utilities and agencies with primacy for drinking water regulations.
• A copy of the site decommissioning plan should be retained by the operator for a minimum of 10 years (or longer if required by the competent authority) following site decommissioning.

Operators should follow the record-keeping and reporting requirements set out in Articles 12, 14, and 25 of the EU Directive 2009/31/EC and Article 67 and Annex IX of the MRR .

Isometric recommends the following as additional best practice guidance for record-keeping:

• All Activity records should be available to the Certification Scheme and the Certification Body, including site characterization, design and construction documentation, laboratory analyses, injection operation records, monitoring data and results, and site closure documentation.
• Documentation of any spills during injection operations and estimates of quantity released.
• Reports of any instrument failures or downtime.

The monitoring plan shall include the mandatory parameters set out in Annex II 1.1(e)–(k) of the EU Directive 2009/31/EC, with monitoring methods, frequencies, and quality assurance procedures as approved in the storage permit under Article 13. The MRR (Articles 40–46) provides the binding measurement methodology, and Article 42 references EN 14181, EN ISO 16911-2, and EN ISO/IEC 17025 for quality assurance. Guidance document 2 Table 3 provides a reference list of applicable monitoring technologies across all phases of the Activity lifecycle.

Where the monitoring plan specifies "Approved Permit" as the evidence reporting method, evidence may be satisfied through submissions to the competent authority in accordance with Section 2.1 (Evidence Reporting) of this Module.

Isometric recommends the monitoring the following additional parameters, specifies instruments, frequencies, or accuracy as best practice guidance:

Pre-injection baseline:

• Overlying formation pressure
• Composition of residual hydrocarbons (for depleted reservoir projects)
• Dissolved gas, DIC, and tracers (δ¹³C)
• Groundwater geochemical composition (pH, conductivity, dissolved CO₂, TDS, isotopes)
• Baseline ecosystem imaging

Injection and operational phase:

• CO₂ concentration: continuous inline analyser (e.g. NDIR, TDL), ≤2% accuracy, 1-minute intervals, annual calibration
• Mass flow: Coriolis or thermal mass flow meter, ≤2% accuracy, annual calibration
• Annulus pressure: continuous monitoring
• Injectate monitoring: sufficient frequency to detect deviations from permitted specifications
• Internal mechanical integrity testing: every 6 months
• External mechanical integrity testing: annually
• Pressure fall-off testing: annually
• Corrosion monitoring: quarterly
• Wellhead gas composition (CO₂, CH₄): monthly, ≥0.01 vol% resolution
• Reservoir imaging (seismic, gravity, electrical): at least every 5 years
• Continuous reservoir temperature and pressure (e.g. fibre-optic DTS)
• Pressure monitoring above the sealing interval
• Pressure fall-off testing: every 2 years
• Formation fluid geochemical monitoring (pH, conductivity, gas composition, DIC, density)
• Surface displacement monitoring (SAR/InSAR, tiltmeters, GPS)
• Ecosystem stress monitoring (phenocams, remote sensing)
• Surface CO₂ density and flux (optical sensors, LIDAR, eddy covariance)
• Tracer testing (CH₄, radon, noble gases, δ¹³C)
• Seismic monitoring with reporting threshold of magnitude ≥2.7 within the storage complex
• Gas detectors with alarms and automatic shut-off systems

Post-injection phase:

• Same monitoring strategy as operational phase, with frequency reduced based on risk-based criteria
• External mechanical integrity testing: annually for first 3 years, then every 5 years
• Corrosion monitoring: annually for first 3 years