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CO₂ Storage via In-situ Mineralization in Mafic and Ultramafic Formations
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Durability (The amount of time carbon removed from the atmosphere by an intervention – for example, a CDR project – is expected to reside in a given Reservoir, taking into account both physical risks and socioeconomic constructs (such as contracts) to protect the Reservoir in question.) refers to the length of time for which CO2 is removed from the Earth’s atmosphere and therefore cannot contribute to further climate change. This moduleModule (Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.) details durability and monitoring requirements for storage (Describes the addition of carbon dioxide removed from the atmosphere to a reservoir, which serves as its ultimate destination. This is also referred to as “sequestration”.) of CO2 removed from the atmosphere and stored in mafic or ultramafic rock formations.
CO2 injection into mafic or ultramafic formations, such as basalts, peridotite and ophiolites, accelerates the natural chemical reaction of mineral carbonation that permanently immobilizes CO2 in the subsurface1. Injected CO2 first dissolves in water before reacting with divalent cations (Ca, Mg and Fe) in the reservoir (A location where carbon is stored. This can be via physical barriers (such as geological formations) or through partitioning based on chemical or biological processes (such as mineralization or photosynthesis).) rocks to form carbonate minerals (e.g., calcite - CaCO3). This process has been demonstrated to rapidly store the majority of injected CO2 within two years of injection at field pilots in Iceland2,3 and the USA4,5. CO2 can be injected as a supercritical fluid or dissolved in water. Dissolution of CO2 into a water phase can occur at the surface, in the injection well, or in the reservoir into formation fluids. Injecting pre-dissolved CO2 (either prior to or during injection) will lower loss of durability risks and result in faster mineralization rates compared to supercritical CO2 injection. This is because dissolving CO2 in water eliminates the buoyancy of CO2 by creating a dense solution (CO2 saturated water) that sinks when injected into the storage reservoir6. To ensure sufficient durability, CO2 characteristics and the conditions within the storage reservoir must be well defined, modeled (A calculation, series of calculations or simulations that use input variables in order to generate values for variables of interest that are not directly measured.) and monitored. Once CO2 is trapped within the reservoir, and there is proof of no free phase migration outside the intended target reservoir or to Underground Sources of Drinking Water (USDWs (An aquifer, or a portion of one, which supplies or has the possibility to supply any public water supply system, or drinking water for human consumption.)) after closure (as per regulating permitting requirements), the carbon dioxideCO2 can be considered ‘permanently’ removed. Geochemical measurements will be critical for demonstrating and quantifying mineralization.
This moduleModule is applicable to dissolved or supercritical CO2 injection into onshore mafic or ultramafic formations (e.g., basalts and ophiolites) that will allow for rapid in-situ CO2 mineralization. Crediting will occur on injection into the reservoir and isolation from the atmosphere.
Potential risks to expected durability are site specific, but generally fall under two categories: chemical (e.g., reactions) [risk A] and physical (e.g., migration out of the targeted reservoir, injectivity) [risk B]. Specific risks may include:
This section outlines requirements for evaluating CO2 injection and storage within mafic and ultramafic systems for mineralization, 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 geologic reservoir (A body of similar rock type (e.g. color, grain size, mineral composition, texture) and a particular location in the stratigraphic column (vertical rock layers). Formations are large enough to be mappable on Earth's surface or traceable in the subsurface.) and does not migrate outside of the reservoir limits, nor convert into gassesgases that may later be re-emitted (e.g., CO2, CH4). The injection site must be monitored in accordance with the country/region’s specific well permitting requirements as specified in the operating permit issued for the injection site. Each site should create a “testing and monitoring plan” which incorporates available, site-specific techniques that support the overall goals of detecting trends or events that might lead to endangerment of Underground Sources of Drinking Water (USDWs (An aquifer, or a portion of one, which supplies or has the possibility to supply any public water supply system, or drinking water for human consumption.)) and demonstrates that the projectProject (An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.) is operating as permitted. This plan should be submitted to the regulating authorities.
The subsurface monitoring approach developed and implemented by the Project Proponent (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) must address the parameters laid out below, via the permitting process and permit compliance, or by additional efforts and documentation.
Table 1. See Section 2.2 for further details.
Specifically, the following requirements must be met to ensure durable storage of CO2 in the geologic reservoir.
The injection site must have a current well permit issued by the responsible authority for the location of the injection facility and reservoir, for example within the USA a Class VI well permit from the EPA (A United States Government agency that protects human health and the environment.) or authorized primacy state level governing agency is required. The permit must specifically identify CO2 as acceptable injectants under the permit. In addition, the projectProject must comply with all applicable local environmental, ecological and social requirements as well as those set out in Section 5 of the DACrelevant Protocol and Section 3.7 of the Isometric Standard. For CO2 mineralization the geologicalgeologic reservoir must allow for rapid in-situ carbonate mineralization.
Wells may not be utilized if the wells are also used for enhanced hydrocarbon recovery (EHR or EHR+) (Enhanced hydrocarbon recovery (EHR) is a tertiary hydrocarbon production technique or process where the physicochemical (physical and chemical) properties of the rock and/or the fluids are changed to enhance the recovery of hydrocarbon, typically by altering the chemical, biochemical, density, miscibility, interfacial tension (IFT)/surface tension (ST), viscosity and thermal properties to enable additional hydrocarbon production (SPE, 2023). EHR+ is the specific use of CO₂ injection for EHR where the CO₂ remains stored in the geologic formation permanently (IEA, 2015).) activities.
The site shouldmust be well characterized in accordance with the permit application and approval requirements under the national/international regulations to demonstrate site suitability for mineralization and containment of CO2. If there is a lack of distinct relevant local regulations to meet the minimum requirements of this moduleModule, projectProject proponentsProponents are required to follow either the U.S. EPA Underground Injection Control (UIC) or EU directives. All projectsProjects are required to clearly report the regulations which are utilized at the site, with any deviations from the relevant national/international standards outlined within the projectProject designDesign documentDocument (PDD) (The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.) upon submission to the relevant validation and verification bodies (VVB) (Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.).
Site characterizations must include evaluation of reservoir chemistry and conditions where required to ensure CO2 will be stored within the reservoir. The permit must define the Area of Review (AOR) (The area surrounding an injection well described according to the criteria set forth in the U.S. Code of Federal Regulations § 40 CFR.146.06, which, in some cases, such as Class II wells, the project area plus a circumscribing area the width of which is either 1⁄4 of a mile or a number calculated according to the criteria set forth in § 146.06.) for the site in accordance with the requirements for the specific well class, formation, and local characteristics.
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 that the geologic system:
These can be demonstrated by laboratory testing of reservoir rocks/cores (e.g., to measure cation availability) or geochemistry, literature data and/or field based approaches such as a pilot injection and to demonstrate solubility and mineral trapping). The laboratory experiments may also include quantification of the rate atof CO2 mineralization. A relevant core could be a representative rock sample from a sister reservoir, or equivalent, but ideally be a core directly sampled from the project site.
This shall be used to create reservoir models/simulations to demonstrate if the reservoir is favorable, by assessing dissolution, migration and expected mineralization and quantifying the expected extent of each process. These models must include an evaluation of potential behaviors from accurate representation of the geological storage complex (i.e., geostatic model), and a geochemical model representing the possible behaviors of the CO2, rocks, minerals and other fluids within the system. Combined or separate reactive transport models are recommended.
Permits may also ensure safety of USDWs. In order to ensure this, the projectProject proponentProponent mustis conductrequired to complete a baseline (A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.) characterization of the system, where applicable, including but not limited to:
Site characterization and predictive reservoir models must be reviewed every 5 years as part of the creditingCrediting periodPeriod (The period of time over which a Project Design Document is valid, and over which Removals or Reductions may be Verified, resulting in Issued Credits.) and regulators permit renewal application minimum, or at the request of the regulating programs Director, 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 must 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.
The Project Proponent must ensure that the injection well is constructed in compliance with the regulator’s permit and according to national or international best practices, and documentation and records of well construction are maintained and available for review.
At a minimum, the Project Proponent must ensure that all injection, observation or monitoring, legacy offset and production wells contained within the delineated AOR have been evaluated. Extra caution should be used on wells which penetrate into the mineralization zone. Wells which pose a risk to durability have been plugged prior to injection in order to:
Casing, cement, tubing, packer, wellhead, valves, piping, or other materials used in the construction of each well associated with the project must have sufficient structural strength and be designed for the life of the project. All surface casing will be set below the lowermost USDW and cemented to the surface. All well materials must be compatible with fluids with which the materials may be expected to come into contact, including CO2 and formation fluids (e.g., corrosion-resistant well casings and CO2 resistant cement) and must meet or exceed standards (Standard physical constants as well as standard values set forth by bodies such as the National Institute of Standards and Technology (NIST) or others.) developed for such materials by API, ASTM International, or comparable standards. The casing and cementing program must be designed to prevent the movement of fluids out of the mineralization 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. Where the jurisdiction issuing the permit has different monitoring requirements to those stated here, please provide justification of any deviation within the PDD (The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.). This plan should be updated every five years, unless the regulatory body that isuesissues the permit requires this to be updated more often, to take account of changes to the assessed risk of CO2 leakage, changes to the assessed risks to the environment and human health, new scientific knowledge, and improvements in best available technology. The risks (see Section 1) addressed by each measurement will be denoted in a square bracket. At a minimum, the permit and associated well operating plan must consider the following:
Additional measurmentsmeasurements may include:
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, maximum flow rate is exceeded, and gas detection systems indicate elevated CO2, CH4, H2 or H2S levels in headspace. If activated the operator must immediately investigate and identify as expeditiously as possible (or in accordance with permit requirements) the cause of the alarm or shutoff, and report the instance to the validation and verification body (VVB).
As applicable based on specific site conditions, formation type, and permit class, monitoring to ensure CO2 migration beyond the AOR 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.
This is required at a site-specific frequency and spatial distribution in order to monitor any CO2 movement to above the reservoir seal and potential impact to underground sources of drinking water (USDW)USDWs [A,B]. This includes monitoring of:
Surface gas, incluidng CO2, H2 and CH4, concentrations and fluxes to identify large point-source leaks every two years. Spatial distribution must be determined using baseline data. Monitoring can be completed using one or more of the following methods:
The pressure within the formation directly above the sealing interval, either measured using monitoring wells or through multiple sealing levels on the injection well.
Geochemical monitoring of USDWs is required periodically (as agreed in the monitoring plan with the regulating authority) for ground water quality and geochemical changes that may result from carbon dioxide or injection formation fluid movement into the overlying formations. Pressure in any overlying aquifer must be monitored. In addtionaddition, fluids should be sampled for:
Additional monitoring of other constituents may be identified by the owner or operator and/or the regulators. This may include but is not limited to any tracer being measured in the injectate, for example minor ions, select trace metals, stable isotopes of C in CO2, CH4 (if present) and DIC, [math: δ^{18}]O and [math: δ]D of H2O, and inert tracer concentrations (e.g., noble gassesgases).
Identification of any natural springs connected to the mineralization formation or USDWs within the storage site, with baseline and annualongoing monitoring to ensure no CO2 leakage (as agreed in the monitoring plan with the regulating authority). This should include:
Ecosystem stress (if required by the permit), which can be an early indicator for CO2 leaks. ThisIdeally, this should be monitored continuously with ad hoc random sampling 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 images1514.
Subsurface monitoring is required to demonstrate that solubility and mineralization trapping are occurring. This should be demonstrated using reservoir conditions, geochemical monitoring and modeling, and should quantify the percentage and rate or timescale of trapping and the amount of potential leakage [A,B].
Geochemical monitoring locations, parameters, tools, spatial and temporal resolutions and detection limits should be defined in the monitoring plan as agreed by the regulating body. This should include but not be limited to:
Reactive and non-reactive tracer data collected from monitoring wells should be combined in order to accurately quantify CO2 trapping within the subsurface (e.g, mineralization) using mass balance equations2,1615:
[math:\tag{Equation 1}[i]_{min}=X\cdot[i]_{is}+(1-X)\cdot[i]_{bf}-[i]_{meas} ]
where(Equation 1)
Where:
Reductions in the recovery of reactive tracers in monitoring wells relative to non-reactive tracers, coupled with concordant shifts in variables such as pH and fluid saturation states, indicates CO2 is being mineralized in the reservoir.
Additional monitoring could include:
If supercritical CO2 is injected into the reservoir, additional subsurface monitoring requirements include [B]:
Reservoir modeling must be performed, including pressure and fracture simulations, to assess CO2 migration and behavior within the subsurface to confirm containment within the AOR. 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/impermeable layer if applicable, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment CO2 within targeted injection zone [A, B]. It should also predict future performance which at a minimum should include: (i) percentage of CO2 dissolving and mineralizing, (ii) comparison of monitoring data with modeled predictions. Data from modeling should be used to further refine the model and prediction both during injection and post injection.
The final list of constituents to be monitored will be determined between the projectProject proponentProponent and regulating body on a project-specific basis using site-specific data from site characterization and injectate composition.
If CO2 leakage is detected from the targeted reservoir or significant irregularities from the model, the Project Proponent/operatorsOperators will need to undertake corrective measures as set out in their monitoring plan submitted and approved by the competent authority.
For a loss of conformance with models, the projectProject proponentProponent is required to:
For CO2 leakage, the projectProject proponentProponent is required to:
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:
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 4 is to put in place scientific and/or operational monitoring practices in order to prove beyond reasonable doubt that CO2 storage will be durable on geologic timescales. Addressing potential risks to durability is important for ensuring robust and diligent carbon dioxide removals (The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.). The projectProject proponentProponent must follow any post-injection and site decommissioning requirements of the permit for the specified projectProject. Post-injection is defined as monitoring between the end of injection and plugging of the wells. Once injection has ceased (this is defined as closure in the EU) the site must undergo post-injection monitoring. Once it is demonstrated that the injectate plume (which has not yet been mineralized) is stable (i.e., no longer migrating) within the storage reservoir and unable to impact on the USDWs, wells can be plugged and the site decommissioned (this is defined as the closure point in the US). Within the EU, the projectProject proponentProponent must transfer the site to the national/local authorities where monitoring will continue. Within the USA, additional post-closure monitoring may be discontinued if allowed under the applicable UIC permit.
It is recommended that for post-injection monitoring 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. This monitoring, therefore, must focus on using reservoir modeling alongside direct measurements from the injection well/monitoring well to confirm mineralization/lack of plume migration. If supercritical CO2 was injected, indirect imaging may also be used. USDWs should also be monitored to identify and address any CO2 leakage pathways that arise. Mechanical integrity of monitoring wells and the injection well should occur annually for the first three years after injection ceasing and every five years until site decommissioning, to ensure the wells do not become a leakage pathway. If applicable and if the pressure front migrates in a new direction, the installation of additional monitoring wells may be required. Any measured parameters should be compared to modeled predictions to help refine the model or identify possible risks. The frequency of post-injection monitoring may be reduced, determined by specific, risk-based, quantitative criteria detailed as part of the regulating permit. Such criteria could include the reservoir pressure reaching a certain level relative to pre-injection conditions or steady or favorable trends (towards mineralization and dissolution) in observed geochemical monitoring results over a predefined period, and agreement with model predictions.
Periodic assessment (15 years (USA) or 20 years (EU) or equivalent, but likely sooner if mineralization can be proved) must be completed to demonstrate mineralization, dissolution and plume stabilization or a trend towards, this time period may change at the discretion of the regulating body. Re-assessments will be carried out until permanent containment of the stored CO2 in order to eliminate the risk of migration or release of CO2 from the storage formation to the atmosphere or USDWs. The projectProject proponentProponent will actively explore emerging technologies for measuring plume stabilization. The plume stabilization assessment must be conducted in one of the following ways:
The timeframe for post injection monitoring should be aligned with regulatory guidance and based on site specific operation and monitoring data, for example where CO2 mineralization (and plume stabilization for supercritical injection) is not demonstrated. If the regulating authority does not have guidance on the minimum timeframe, this is set at a minimum of 50 years, unless mineralization can be proven.The length of ongoing monitoring will be subject to change given subsequent reanalyses.
If the CO2 mineralization (and plume stabilization for supercritical injection) can be demonstrated by the above methods, and is independently reviewed and certified by a registered Professional Geologist (i.e. Chartered Geologist or equivalent), the CO2 will be considered stabilized and the site decommissioned following requirements in Section 4.
Based on present levels of scientific knowledge, projectsProjects applicable to this protocolModule are categorized as having a Very Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire. This is because there should be no reversals unless there is a loss of caprock or well integrity, and this technology does not yet have a documented history of reversals. There is, however, a risk of methane production within the reservoir, based on current literature, but this risk is very small2019. As a result, a 2% buffer pool (A common and recognized insurance mechanism among Registries allowing Credits to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.) will be set aside as a precaution. This reversal risk will be reassessed every 5 years, aligning with the creditingCrediting periodPeriod, or when new scientific research and knowledge are produced.
Reversals will be accounted for by projectsProjects and the Isometric Registry (A database that holds information on Verified Removals and Reductions, and reviewed EACs, based on Protocols. Registries Issue Certificates, and track their ownership and Retirement.) as detailed in Section 5.6 of the Isometric Standard.
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.
If the Project Proponent was the only entity injecting into a given reservoir, the Project Proponent will take on 100% of the reversal.
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:
In instances where reversals are determined to be a result of negligence by the Operator or Project Proponent, projectProject creditingCrediting may be ceased.
[math: CO_2e_{Stored}] represents the amount of CO2 present in the CO2-containing injectant that is injected and stored in the geologic or engineered storage formation in a given Reporting Period ([math: RP]). This is the gross mass stored and does not account for reversals of storage from the storage formation.
This can be calculated by using the mass injected and the average concentration of CO2 in the injectant over a given time period, summed across the whole [math: RP]:
[math: CO_2e_{Stored,\ RP} = \sum_{t=1}^{T} C_{mean, inj,t} \cdot m_{inj,t}]
(Equation 2)
Where:
The mass of CO2-containing injectant, [math: m_{inj,t}], may either be directly measured using a mass flow meter, or may be indirectly measured by combining suitable volume and density measurements. In the latter case, the mass of injectant is calculated as:
[math: m_{inj,t} = V_{inj,t} \cdot \rho_{inj,t} ]
(Equation 3)
Where:
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 [math: CO_2e_{Stored}] requires two primary measurements
The concentration of CO2 in the gaseous, dissolved or supercritical CO2 stream must be:
The mass of injectant ([math: m_{inj}]) is measured via use of a calibrated mass flow meter or volumetric flow meter and density measurements over a defined time interval ([math: 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:
In general, the Project Proponent must identify, highlight, and explain any data gaps or missing calibration data, if any occur. The Project Proponent must notify Isometric and the VVB when data gaps or missing calibration data occur and must clearly explain the approach taken and document the missing data within the GHG statement.
For those parameters where frequent, sub-hourly measurements are required (notably CO2 concentration measurements in the CO2 stream, and the measurement of mass of CO2 injected), the Project Proponent must adhere to the following procedure for handling missing data.
Where there are data gaps in measurement of the relevant parameter of up to 30 minutes, the Project Proponent may claim using an average quantity, based on the measurements proceeding and following the data gap.
Where there are such data gaps of longer than 30 minutes, the Project Proponent may apply this approach for up to a 30 minute period within the duration of the data gap, but no more than this. For the remainder of the period of the data gap, i.e. in excess of 30 minutes, no carbon dioxide removal may be claimed, due to a lack of data. In addition, data gaps must account for less than 5% of the data used for the removal calculation within a given Reporting Period, any missing data above this is also not creditable.
Where a calibration is missed, one must be completed as soon as this is noticed. For data collected between when the calibration was required and when it actually took place, a conservative estimate should be used agreed between the VVB, Project Proponent, and Isometric.
The Project Proponent must maintain the following records as evidence of gross CO2 stored in injected CO2 or CO2-containing injectant:
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.
[math: CO_{2}e_{Emissions}] is the total greenhouse gas emissions associated with a given Reporting Period, [math: RP].
Equations and emissions calculation requirements for [math: CO_{2}e_{Emissions}], including considerations for monitoring activities, are set out in the relevant protocolProtocol and are not repeated in this moduleModule.
In order to decommission a site, the projectProject proponentProponent must prove beyond reasonable doubt that injected CO2 will cause no harm to USDWs and stay within the AOR and thus CO2 storage will be durable on geological timescales. The projectProject proponentProponent must ensure that all the regulators permit requirements associated with planning for, proceeding with and monitoring of well or site decommissioning are adhered to and documented.
Decommissioning of the site must follow local statutory requirements. If supercritical CO2 was injected, the projectProject proponentProponent, during decommissioning, must 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 using CO2 resistant cement and to the regulators requirements. For dissolved injections, well cementing is not required as part of this moduleModule as when solubility/dissolution trapping has been confirmed the risk of release from the geological storagegeologic reservoir is negligible.
A site report (providing information on the operation, monitoring & modeling and closure procedures) should be created by the projectProject proponentProponent and submitted to regulatory bodies and carbon storage agreements with pore space owners will ensure activity in the storage site is prohibited for perpetuity following CO2 injection, ensuring that even if any supercritical CO2 does not dissolve or precipitate, it will not be subject to pressure disturbances (i.e, injection or production activities) in the storage reservoir and land owners will be aware. It is also recommended that the projectProject proponentProponent notifies other stakeholdersStakeholders (Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.), such as nearby drinking water utilities and agencies with primacy for drinking water regulations. A copy of the site decommissioning plan should also be retained by the projectProject proponentProponent for a minimum of 10 years (or longer if required by the regulator) following site decommissioning.
Within the US, site decommissioning does not eliminate any potential responsibility or liability of the owner or operator under other provisions of law. For example, the projectProject proponentProponent may still hold some responsibility for any remedial action deemed necessary for USDW endangerment caused by the injection operation.
Within the EU, the site is transferred from the projectProject proponentProponent to a competent authority (i.e., national or local authorities) once mineralization, dissolution and plume stability has been established and the site decommissioned. After the transfer of responsibility, the competent authority will continue with monitoring at a reduced rate which still allows for identification of CO2 leakages or significant irregularities. This will be intensified if CO2 leakages or significant irregularities are identified.
All records associated with the characterization, design, construction, injection operation, monitoring, and site closure must be developed, submitted to proper authorities as required by the regulating permit.
All records must be maintained for a minimum of 10 years after the injection. All closure and post-closure monitoring records must be maintained by the projectProject proponentProponent for a minimum of 10 years after closure. These records must be available to be consulted by interested parties for future clarifications if needed.
Isometric would like to thank Chris Holdsworth (University of Edinburgh as of the time of contributing) for contributing to this moduleModule.
Isometric would like to thank James Campbell, Ph.D. (Heriot-Watt University) for reviewing this moduleModule.
This appendix details how the Project Proponent must monitor, document and report all metrics identified within this Module to demonstrate the durability of CO2 removal. Following this guidance will ensure the Project Proponent measures and confirms CO2 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 creditingCrediting.
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.
| Parameter | Parameter Description | Measurement | Measurement description | Monitoring phase | Required by the protocol | Required under certain conditions | Measurement Method | Monitoring Frequency | QA/QC Procedures | Required Evidence | Reference in | |
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Onsite characterization | Divalent cation concentrations in lithology | Concentration of Mg and Ca within the targeted formation | Pre Injection | Yes | e.g., EPMA, XRD, XRF, SEM-EDX | Once | In a relevant ISO or ATSM accredited laboratory | Analytical reports from qualified laboratory for audited samples, including supporting lab QA/QC results | ||||
| Porosity & permeability | Porosity & permeability of | Pre Injection | Yes | As per permit requirements | Once | Permit or testing data | ||||||
| Reservoir volume | Pre Injection | Yes | As per permit requirements | Once | Permit or testing data | |||||||
| Reactive surface area of target formation | Pre Injection | Yes | Once | |||||||||
| Reservoir injectivity | Pre Injection & Operation | Yes | As per permit requirements |
| Permit or testing data | |||||||
| Characteristics of the impermeable layers/confining layer | Thickness and entry pressure and reactivity of the confining/impermeable layers | Pre Injection | Yes | As per permit requirements | Once | Permit or testing data | ||||||
| Fluid saturation | Fluid saturation of reservoir pore spaces | Pre Injection | Yes | Either wireline log or core | Once | As per manufacturer calibration procedure | Data logs/data acquisition system output | |||||
| Reservoir fluid composition | pH formation fluid | pH of reservoir formation fluid prior to injection and during operation | Pre Injection | Yes | pH meter |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||
| Conductivity or other salinity measurement of formation fluid | Salinity of reservoir formation fluid prior to injection | Pre Injection | Yes | National/International approved method e.g., ASTM Designation D1125-82 or other |
| As per manufacturer calibration procedure | Data logs/data acquisition system output or analytical reports from qualified laboratory for audited samples, including supporting lab QA/QC results | |||||
| Tracers composition in the injectate | Reactive (inherent and/or spiked) and non-reactive tracers used to identify and quantify mineralization within the targeted formation. This could include DIC concentration, stable isotopes of CO2 or CH4, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water) | Pre Injection, Operation | Yes | Set of tracers measured depends on | Tracer dependent |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||
| ||||||||||||
| Surface Elevation | Surface topography for baseline for elevation monitoring | SAR/InSAR | Pre Injection |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||||
| Subsurface/subsurface tiltmeters |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | |||||||||
| GPS Instruments |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | |||||||||
| USDW composition | Geochemical composition of USDWs | pH | Pre Injection | As required by permit | pH meter |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||
| Temperature | Pre Injection | As required by permit | Temperature probe/sensor |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||||
| Conductivity | Conductivity of the USDW | Pre Injection | As required by permit | National/International approved method e.g., ASTM Designation D1125-82 or other |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | |||||
| Dissolved gas concentrations | Pre Injection | As required by permit | Gas chromatography |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||||
| Tracers composition in the injectate | Reactive (inherent and/or spiked) and non-reactive tracers used to identify and quantify mineralization within the targeted formation. This could include DIC concentration, stable isotopes of CO2 or CH4, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water) | Pre Injection | Under certain conditions |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||||
| Pressure in the overlying aquifers | Pre Injection, Operation | Yes |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.3.1 | ||||||
| Ecosystem imaging | Site based phenocams or medium-to-high resolution remote sensing to capture baseline | Pre Injection | As required by Permit |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | ||||||
| Geophysical imaging | Geophysical survey to assess subsurface structure | Pre Injection & operation | Yes for Pre injection, Under certain circumstances for operation | When supercritcial CO2 is inejcted |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 2.2, 3.1.3.2 (CO2 Storage via In-Situ Mineralization) | ||||
| Injection pressure | Surface injection pressure aligned with local requirements | Operation | Yes | As per permit requirements | Continuous | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | ||||
| Annulus pressure/ fluid volume | Pressure and fluid volume in the annulus between the tubing and the long string casing | Operation | Yes | As per permit requirements | Continuous | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | ||||
| Injection rate/volume | Rate and volume of fluids being injected | Operation | Yes | Continuous | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | |||||
| Injectate stream composition | Composition of the injectate | pH of injectate stream | pH of injectate stream | Operation | If dissolved CO2 is injected | pH meter | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | |||
| Temperature of injectate stream | Temperature of injectate stream | Operation | Yes | Temperature probe/sensor | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | |||||
| CO2 concentration of injectate stream | CO2 concentration of injectate stream (this is repeated from the Net CO2e calculations) | Operation | Yes | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | ||||||
| Impurity concentrations in the injectate stream | Impurity concentrations in the injectate stream e.g., arsenic, sulfides and mercury | Operation | Under certain conditions | If supercritical CO2 injection | ICP-MS | As per permit | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | |||
| Operation | Under certain conditions | If dissolved CO2 injection | Gas chromatography | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | ||||||
| Density of | Calculated using the data from CO2 and injection water | Pre-Injection & Operation | Under certain conditions | If dissolved CO2 is injected |
| 3.1.1 (CO2 Storage via In-Situ Mineralization) | ||||||
| Tracers composition in the injectate | Reactive (inherent and/or spiked) and non-reactive tracers used to identify and quantify mineralization within the targeted formation. This could include DIC concentration, stable isotopes of CO2, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water) | Operation | Yes | Set of tracers measured depends on | Tracer dependent | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.1 (CO2 Storage via In-Situ Mineralization) | ||||
| Internal mechanical integrity tests | Demonstration of internal mechanical integrity | Operation | Yes | As per permit requirements | 3.1 | |||||||
| External mechanical integrity tests | Demonstration of external mechanical integrity | Operation | Yes | e.g., oxygen activation log, temperature log/sensor or noise log. | As per | 3.1.2 | ||||||
| Pressure fall off test | Pressure fall off test | Operation | Yes | UIC or equivalent pressure falloff testing guidelines | Per testing protocol | Data logs/data acquisition system output | 3.1.2 | |||||
| Surface CO2 concentrations | Determine CO2 levels at the surface to help identify leaks | Surface gas concentrations | For example soil gas using optical CO2 sensors, Eddy Covarianace, portable/stationary detectors, or inherent tracers | Pre Injection, Operation |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | |||||
| Wellhead gas concentrations | Operation | Yes | Continuous | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3. | ||||||
| CO2 concentrations around wells | Operation | Under certain conditions | When gas is detected at the wellhead | Wellhead gas sampling; gas monitor if limits breached | Continuous | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.3 | ||||
| Water table | Water table depth to ensure that water is not being over extracted | Operation | Under certain conditions | If using groundwater to dissolve the CO2 | E.g., Tape or Geophysical surveys | 6 monthly | 3.1.3.1 (CO2 Storage via In-Situ Mineralization) | |||||
| Natural spring composition | Composition of any natural presents within the AOR that intersect the mineralization formation or USDWs, to monitor for any signs of leakage. Baseline measurements are required | pH of natural springs | Pre Injection | Under certain conditions | If present and required by permit | pH meter |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 2.2, 3.1.3.1 | ||
| Temperature of natural springs | Pre Injection | Under certain conditions | If present and required by permit | Temperature probe/sensor |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 2.2, 3.1.3.1 | ||||
| ||||||||||||
| Conductivity of natural springs | Pre Injection | Under certain conditions | If present and required by permit | National/International approved method e.g., ASTM Designation D1125-82 or other |
| Data logs/data acquisition system output or analytical reports from qualified laboratory for audited samples, including supporting lab QA/QC results | 2.2, 3.1.3.1 | |||||
| Dissolved gas concentration (including DIC) of natural springs | Pre Injection | Under certain conditions | If present and required by permit | Gas chromatography |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 2.2, 3.1.3.1 | ||||
| Tracers composition in the injectate | Reactive (inherent and/or spiked) and non-reactive tracers used to identify and quantify mineralization within the targeted formation. This could include DIC concentration, stable isotopes of CO2, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water) | Pre Injection | Under certain conditions | If present and required by permit. Set of tracers measured depends on |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 2.2, 3.1.3.1 | ||||
| Core analysis | analysis of core for evidence of mineralization | Not required but helpful | 3.1. | |||||||||
| Seismic monitoring | Seismic monitoring | Operation | Under certain conditions | As per permit requirements | As per permit requirements | Continuous | As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1. | |||
| Reservoir pressure | Pressure within the reservoir, either measured at bottomhole or calculated using the wellhead pressure | Yes | Using pressure gauge or sensor |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.3.2 | |||||
| Temperature within the targeted reservoir for mineralization | Yes | Temperature probe/sensor |
| As per manufacturer calibration procedure | Data logs/data acquisition system output | 3.1.3.2 | ||||||
| Hydrologic tests | Comparative hydrologic tests to identify changes in the reservoir hydraulic and/or storage characteristics attributed to injection | Operation | Not required but helpful | Only for supercritcal CO2 injection | e.g., freshwater injection/recovery testing followed by a series of instantaneous pressurized slug/pulse withdrawal tests or wireline geophysical surveys. | 3.1.3.2 (CO2 Storage via In-Situ Mineralization) | ||||||
| Reservoir modeling | Modeling of the reservoir including pressure and fracture simulation to assess CO2 migration and behavior and to ensure containment. Including a predictive component | Pre Injection, Operation | Under certain conditions | Operation required | Model type, inputs and outputs |
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