CO₂ Storage via In-situ Mineralization in Mafic and Ultramafic Formations v1.0

1.0 Introduction

Durability (The amount of time carbon removed from the atmosphere by an intervention – for example, a CDR project – is expected to reside in a given Reservoir, taking into account both physical risks and socioeconomic constructs (such as contracts) to protect the Reservoir in question.) refers to the length of time for which ~~carbon dioxide~~CO₂ is removed from the Earth’s atmosphere and therefore cannot contribute to further climate change. This module (Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.) details durability and monitoring requirements for storage (Describes the addition of carbon dioxide removed from the atmosphere to a reservoir, which serves as its ultimate destination. This is also referred to as “sequestration”.) of CO₂ removed from the atmosphere and stored in 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 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 dioxide can be considered ‘permanently’ removed. Geochemical measurements will be critical for demonstrating and quantifying mineralization.

This module 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:

Redissolution of carbonates already precipitated as injection continues [risk A]
- The injection of CO₂ will decrease the pH within the reservoir and potentially result in the dissolution of carbonates that have previously been mineralized. This CO₂ will be dissolved and thus more mobile than in carbonates. For supercritical CO₂ injection, the reservoir must have a confining layer to ensure that CO₂ will be contained and durably stored. For dissolved CO₂ injection, which is much less mobile, the reservoir will also ideally have a confining or impermeable layer, however where this is not present, further site charaterization and additional geochemical monitoring and pressure will be required. Furthermore, it is likely that this CO₂ will be remineralized downstream ensuring durbale storage ².
Mineralization causes a loss of permeability and/or decrease in pore space [risk B]
- As mineralization occurs, injectivity to the storage reservoir could decrease due to a loss of permeability and pore space, particularly if mineralization occurs close to the injection wellhead. In this scenario, the reservoir capacity for CO₂ storage will decrease, but the durability of CO₂ that has already been injected and mineralized will not be impacted.
Formation of a gas phase [risk A, B]
- Changes in reservoir pressure and temperature could result in the exsolution of some gaseous CO₂ [risk B].
- CO₂ could be microbially consumed to form CH₄⁷ [risk A]. This risk is thought to be greater for supercritical CO₂ injection ⁷.
- Indicators of CO₂ exsolution and biogas production should be monitored as part of the post-injection monitoring plan (see Section 3.2). Any gasses produced will be considered removed if one or more confining layers are present that prevent the vertical migration of buoyant phases. Any releases of gasses from the storage reservoir must be accounted for as reversals (The escape of CO₂ to the atmosphere after it has been stored, and after a Credit has been Issued. A Reversal is classified as avoidable if a Project Proponent has influence or control over it and it likely could have been averted through application of reasonable risk mitigation measures. Any other Reversals will be classified as unavoidable.) (see Section 3.3).
Induced seismicity can change reservoir properties [risk B]
- The injection of CO₂ and water can induce seismicity within a reservoir which can alter the reservoir connectivity and flow paths. This risk may be a greater risk when injecting dissolved CO₂ due to the large volume of fluid that would need to be injected into the subsurface. Prior to any injection activity a site-specific study of the regional seismicity must be performed.
Predicted trapping rates are lower than predicted [risk A]
- Mineralization within the reservoir could be less than initially predicted in reservoir models as a result of a limited supply of cations and/or reactive surface area. In this scenario, injected CO₂ would remain mobile either as a supercritical liquid or dissolved in water. As long as the reservoir has an impermeable confining layer or remains dissolved within the mineralization zone, CO₂ will be considered contained and durably stored. Any releases of this injected CO₂ from the storage reservoir must be accounted for (see Section 3.3).
- For supercritical CO₂ dissolution rates may also be lower than initially predicted in reservoir models. In this scenario, injected CO₂ would remain mobile either as a supercritical liquid or gas phase. As long as the reservoir has an impermeable confining layer, CO₂ will be contained and durably stored. Any releases of this injected CO₂ from the storage reservoir must be accounted for (see Section 3.3).
Migration of free phase CO₂ outside of the intended formation [risk B]
- For supercritical injection, the CO₂ plume will migrate within the reservoir and the injected plume could migrate further or have more limited dissolution than reservoir models initially predicted. 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.
- Breach in well integrity leading to the leakage ~~(The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities.)~~ of CO₂ into the overlying formation. Injection, monitoring, and well integrity testing procedures should be updated during monitoring in order to ensure well integrity.
- Migration of dissolved CO₂ into the overlying formation may also result in CO₂ exsolution due to the decreased hydrostatic head.

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 gasses 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 project (An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.) is operating as permitted. This plan should be submitted to the regulating authorities.

The subsurface monitoring approach developed and implemented by the ~~project~~Project ~~proponent~~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.

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

Table 1. See Section 2.2 for further details.

Parameter	Purpose
Reservoir lithology and mineralogy to ensure there are sufficient cations (CaO, MgO, FeO) which have not been altered	Input into reservoir models allowing for trapping mechanisms (e.g., mineralization and dissolution) predictions
Porosity, effective porosity, permeability, reactive surface area and volume of mineralization zone strata	Demonstrate the capacity and injectivity of the target formation to receive and safely store CO₂
Permeability and structural integrity of confining or impermeable layer	Demonstrate that any buoyant fluids or gasses will be trapped and unable to migrate upwards out of the reservoir
Temperature, pH, conductivity, density, composition of any tracers used and fluid saturation of geologic reservoir formation fluid/brine	For density and input into reservoir models which will guide injection and dissolution models for supercritical CO₂ injection
Concentration and δ¹³C signature of DIC and DOC as well as major and minor ion composition in formation fluid	Determine trapping mechanisms that may occur and for ~~leakage~~leak tracing if required
Surface elevation models, where applicable, which account for natural variation over a year.	Baseline for future measurements and allows inferences about pressure changes at depth.
Soil gas concentrations, where applicable	As a baseline for future measurements to determine if ~~leakage~~leaks isare occurring
Geochemical composition of USDWs within the Area of Review (AOR) (The area surrounding an injection well described according to the criteria set forth in the U.S. Code of Federal Regulations § 40 CFR.146.06, which, in some cases, such as Class II wells, the project area plus a circumscribing area the width of which is either 1⁄4 of a mile or a number calculated according to the criteria set forth in § 146.06.)⁸. This should include but is not limited to: pH, temperature, conductivity, major ions, dissolved gas concentrations and tracers (if using). Recommended additional measurements could include δ¹⁸O and δD of H₂O of the fluids, minor ions, density and δ¹³C of [DIC].	As a baseline for future measurements to determine if ~~leakage~~leaks isare occurring
Baseline ecosystem imaging, where applicable, using the combination of high-resolution aerial hyperspectral imaging and medium-resolution long-term data from Landsat sensors	As a baseline for future measurements to determine if ~~leakage~~leaks isare occurring

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, CO₂-water ratio (for dissolved CO₂ injection), 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 body.
Closure and Post-Closure Requirements: Requirements for proper closure of the storage reservoir and injection facility, as well as post closure requirements and post-injection monitoring to ensure CO₂ is mineralized and 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 geologic reservoir.

2.0 Permitting and Site Characterization

2.1 Permitting

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 is required. The permit must specifically identify CO₂ as acceptable injectants under the permit. In addition, the project must comply with all applicable local environmental, ecological and social requirements as well as those set out in Section 5 of the DAC Protocol and Section 3.7 of the Isometric Standard. For CO₂ mineralization the geological 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.

2.2 Site Characterization and Feasibility Requirements

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

The ~~project~~Project ~~proponent~~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~~Project ~~proponent~~Proponent must demonstrate that the geologic system:

Includes a mineralization zone of sufficient volume, porosity, permeability, and injectivity to receive the total anticipated volume of the CO₂ and to facilitate CO₂ migration.
Has sufficient divalent cations (Mg, Ca, Fe) available for the CO₂ mineralization process within the mafic or ultramafic rocks, for example at Carbfix this number is ~25 wt%⁹ while in the Columbia River Basalts it is ~16 wt%¹⁰ and peridotites is >50 wt% ¹¹.
Has sufficient surface area for the reactions to take place, or a plan to engineer an increase in surface area to allow for the reactions.
For supercritical CO₂ injection, includes a confining system free of transmissive faults and fractures and of sufficient extent and thickness to contain the injected supercritical CO₂ and any gas generated if applicable. It should also allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); the confining system 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;
For dissovled CO₂ injection, includes an impermeable layer (of sufficient thickness with a known and appropriate entry pressure and reactivity) and/or has sufficently characterised the mineralization zone and overlying lithologies (including permeability, reactivity and transmissive faults and fractures) to understand all possible fluid migration pathways that need to be monitored.
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 for example using the same or similar traffic light system as was designed for Reykjavik Energy¹².

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 at 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 also ensure safety of USDWs. In order to ensure this, the project proponent must conduct a baseline characterization of the system, including but not limited to:

Surface elevation models
Soil gas composition incluidng CO₂, H₂ and CH₄, and fluxes over a period of a year to characterize any background spatial and temporal trends and variability.
Geochemical composition of USDWs and any natural springs connected to the mineralization zone or USDWs present within the AOR, to provide baseline measurements for which changes can be used to assess CO₂ leakage. This should include but is not limited:
- temperature
- pH
- conductivity
- major ions
- dissolved gas concentrations (CO₂ impurities)
- DIC concentrations
- tracers (if using)
Baseline ecosystem imaging, where applicable.
Baseline geophysical surveys to characterize the reservoir. In addition, for supercritical CO₂ injection, in accordance with the agreed monitoring plan, geophysical surveys should be conducted during site characterization to create a baseline for which changes in the subsurface induced by the injection operation to be assessed.

Site characterization and predictive reservoir models must be reviewed every 5 years as part of the crediting period (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.

2.3 Well Construction Requirements

The ~~project~~Project ~~proponent~~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~~Project ~~proponent~~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:

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

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

3.0 Monitoring

3.1 Injection and Operational Monitoring Requirements

The ~~project~~Project ~~proponent~~Proponent will ensure that the injection facility complies with the well permit, including the development and implementation of the well operating plan as required by the permit. This plan should be updated every five years, unless the regulatory body that isues 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:

3.1.1 Injection and Injectant Operation & Monitoring

Maximum allowable surface injection pressure (MASIP) at the injection wellhead that is allowed during injection operations to prevent fracturing of the formation, set according to the regulators permit. Injection operation pressures must 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.
The pressure when the injected CO₂ stream enters the storage reservoir. This should be greater than the bubble point pressure¹³ of the dissolved CO₂ (under reservoir conditions). This is to ensure a reservoir pressure >5 bar higher than the bubble point pressure and enable immediate and complete solubility trapping of CO₂¹⁴ [A]. Reservoir pressure can either be measured at the bottom of the well or calculated using the hydrostatic pressure gradient for the AOR reservoir and water table depth.
- Bubble point pressure must be calculated at least monthly, using appropriate geochemical tools (e.g., PHREEQC software version 3), thermodynamic databases and equations of state (e.g., Peng-Robinson). It must include consideration of the:
  - Mass flow rate of the CO₂ stream entering the injection well.
  - Mass flow rate of the water stream entering the injection well.
  - Temperature of the water stream entering the injection well.
  - Temperature of the CO₂ stream entering the injection well.
  - Elemental/gas/dissolved gas composition of the CO₂ stream entering the injection well.
  - Elemental composition of the water stream entering the injection well.
Maximum CO₂ injection rate to monitor volumes injected, prevent induced seismicity or return of injectant. In the case of dissolved CO₂ injection, this will also monitor the CO₂-water ratio (and the rate of each) to ensure all CO₂ dissolves. 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 (see Section 7.4.1.2 of the DAC protocol).
- Monitoring and documentation of injection rate must be performed and records maintained for review. This should also be used to calculate the cumulative volume of CO₂ injected.
- More information can be found within Section 7.4.1.4 of the relevant protocols.
Analysis of the CO₂ with sufficient frequency to yield data representative of its chemical and physical characteristics, using industry standard or indicated methods and quality and properly calibrated equipment [B]:
- pH and temperature
- CO₂ concentration (i.e., wt% CO₂, ~~carbon~~C content). More information on these measurements can be found in Sections 7.4.1.2 of the DAC protocol and 7.4.1.3 of the relevant protocols.
- Gas/dissolved gas composition including impurities that might alter corrosivity, properties of the injectate downhole, or reactivity with the reservoir rocks/fluids (e.g., arsenic, hydrogen sulfide, mercury).
- Density of dissolved CO₂
- If dissolved CO₂ is being injected, major ions should, and [math: δ^{18}]O, [math: δ]D could, also be measured.

Additional measurments may include:

δ¹³C of the CO₂/DIC (if dissolved)
Use of tracers (added and/or inherent) when required. Reactive tracers could include [math: ^{14}]C and [math: δ^{13}]C, non-reactive tracers could include naphthalene sulfonates and noble gasses.
minor ions within dissolved CO₂ streams.

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.

~~Required~~Wells must have gas detectors (or equivalent sensors/imaging) with alarms and ~~automatic surface~~injection shut-off systems (e.g., automatic shut-off, ~~check~~or ~~valves)~~procedures in place for ~~wells,~~manual orshut ~~other~~off ~~mechanical~~of ~~devices that provide equivalent protection~~injection/operation), including, at a minimum, injection pump shutoff when maximum pressure is reached, maximum flow rate is exceeded, orand 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).

3.1.2 System Integrity Monitoring

A demonstration of internal mechanical integrity performed and reported every 6 months. This includes identifying any loss of mass, thickness, cracking, pitting, and 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 [B].
A demonstration of external mechanical integrity annually beginning 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 [B].
A pressure fall-off test, annually [B].

3.1.3 Migration, Trapping and Storage Reversal Monitoring

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.

3.1.3.1 Near surface monitoring

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) [A,B]. This includes monitoring of:

CO₂ concentrations around the well head and personal CO₂ detector on all operators.
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:
- Optical CO₂ sensors, such as airborne infrared spectroscopy, non-dispersive infrared spectroscopy, cavity ring-down spectroscopy or LIDAR (light detection and ranging)
- Eddy covariance (EC) flux measurement at a specified height above the ground surface
- Portable or stationary carbon dioxide detectors
- Tracer testing using inherent tracers such as radon, noble gasses, and [math: δ^{13}]C of CO₂/CH₄, provide a unique fingerprint for the CO₂ or assocaited gases that can be identified in aboveground emissions .
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 addtion, fluids should be sampled for:
- pH
- Temperature
- Conductivity
- Major ions
- Dissolved gas concentrations
- DIC concentrations
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 gasses).
If using dissolved CO₂, water table and competing water usages should be monitored.
Identification of any natural springs connected to the mineralization formation or USDWs within the storage site, with baseline and annual monitoring to ensure no CO₂ leakage. This should include:
- pH
- Temperature
- Density
- Conductivity
- Dissolved gas concentrations
- DIC concentrations
Ecosystem stress, which can be an early indicator for CO₂ ~~leakage~~leaks. 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 images¹⁵.

3.1.3.2 Subsurface monitoring

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].

Continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) and periodic (6 monthly) measurement of formation water density (to determine the likelihood of clogging or decreases in injectivity). Measurement of in-situ fluid pressure that may be achieved using transducers placed within monitoring wells in the injection zone, behind casing gauges, or through direct measurement of fluid depth through a perforation.
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 tracer testing:
  - Inherent tracers: Reservoir fluid sampling from the monitoring well(s) including but not limited to major ion, pH, temperature and DIC concentrations. DIC loss is expected along the flowpath from carbonate mineralization. This sampling should occur monthly unless the regulating permit requires more regular testing. Other inherent reactive tracers that could be used include [math: δ^{13}]C-CO₂/DIC, [math: δ^{44}]Ca and [math: δ]D and [math: δ^{18}]O of H₂O.
  - Spiked tracers: Reactive tracers (e.g., [math: ^{14}]C) can also be added to the injected CO₂ stream. This should be performed following industry best practices. Spiked reactive tracers can lower uncertainties in any mass balance calculations, and may be required in systems where baseline DIC could not be determined, for example [math: ^{14}]C concentrations within the fluids would be very low compared to the injected concentrations.
  - A comparison of the inherent or spiked pre- and post- injection can be used to quantify the amount of CO₂ dissolved and/or precipitated. For example, the amount of DIC loss compared to concentrations in the injected dissolved CO₂ can be used to quantify CO₂ mineralization².
- Non-reactive tracer testing:
  - Non reactive tracers (e.g., noble gases) should be co-injected or measured if inherent with the CO₂ once the project has reached stable operation or within the first two years of injection (whichever occurs earlier or is most appropriate for the project, in line with findings from the Carbfix Project¹⁴) then sampled for in the monitoring well(s). Tracer tests should be performed according to industry best practices.
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^,¹⁶:
```
[math: \tag{Equation 1} [i]_{min}=X\cdot[i]_{is}+(1-X)\cdot[i]_{bf}-[i]_{meas}   ]
```
where [math: i] is the concentration of the reactive tracer (e.g., DIC, ¹⁴C), and [math: X] is the fraction of injectate relative to formation fluid present in the sample (calculated using non reactive tracers). The subscripts [math: min], [math: is], [math: bf] and [math: meas] refer to the amount mineralized, in the injectate, background reservoir fluid and measured during monitoring, respectively.
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.
- Gas concentrations (including CO₂, CH₄ and H₂) where free gas is present
Additional monitoring could include:
- Physical evidence and signatures of mineralization from the reservoir using drill cores.
- A seismic monitoring program may be suggested at the discretion of the UIC director or equivalent in areas of increased seismic risk, where demonstrated that seismicity may have an impact on the formation and the long duration storage of CO₂. This shall include deeper wireline or cemented subsurface geophones for microseismic monitoring and could be combined with at/near ground level stations as part of an intergrated strategy. The purpose of this is to determine the presence or absence of any induced micro-seismic activity associated with all wells and near any discontinuities, faults, or fractures in the subsurface, or any seismic activity in the area within the AOR of the injection facility and the area of the storage reservoir of magnitude 2.7 or greater [B].
If supercritical CO₂ is injected into the reservoir, additional subsurface monitoring requirements include [B]:
- Subsurface imaging may be required by the regulators. This includes reservoir imaging (seismic, gravity and/or electrical methods) and comparison to baseline conditions and reservoir models. This will allow the presence or absence of elevated pressure within the injection zone and the extent of the CO₂ plume to be tracked.
- Comparative hydrologic tests where required to identify changes in the reservoir hydraulic and/or storage characteristics attributed to injection⁵. This could include freshwater injection/recovery testing followed by a series of instantaneous pressurized slug/pulse withdrawal tests and wireline geophysical surveys. Results can be used within calibrated numerical models to quantify the amount of injected CO₂ that was mineralized.

3.1.3.3 Reservoir Modeling

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 project proponent and regulating body on a project-specific basis using site-specific data from site characterization and injectate composition.

3.1.3.4 LeakageCO₂ leakage

If ~~any~~CO₂ leakage is detected from the targeted reservoir or significant irregularities from the model, the ~~project~~Project ~~proponent~~Proponent/operators 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 project proponent is required to:

Halt injection while they identify the cause of this loss
Modify operations to increase dissolution/mineralization
Pause injection and monitor for dissolution/mineralization (this will likely be the case if solubility trapping is slower than expected), and /or
Update their monitoring plan and approve with the UIC director or equivalent

For CO₂ leakage, the project proponent is required to:

Halt injection while an assessment is conducted
Determine if the loss of containment can be repaired prior to injection beginning again
Quantify the amount of CO₂ lost

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 and unexpected migration of the CO₂ plume which suggests potential movement of CO₂ outside the intended formation
CO₂ migration into a zone above the storage complex
CO₂ plume or elevated pressure extend beyond analytical model expectation because any of the following has occurred:
- An seismic event of magnitude 2.7¹⁷ or greater within the AOR;
- New site characterization data change the model inputs to such an extent that the predicted CO₂ fluid and/or pressure plume extends vertically or horizontally beyond what was originally predicted.

Further information on the risk and attribution of reversals Section 3.3 and Section 3.3.1.

3.2 Post-injection Monitoring Plan

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 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 (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 project proponent 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 project proponent will actively explore emerging technologies for measuring plume stabilization. The plume stabilization assessment must be conducted in one of the following ways:

Geochemical and/or tracer to demonstrate CO₂ mineralization, dissolution and 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 AOR.
Core studies to verify mineralization within the reservoir¹⁸^,¹⁹.
Utilize predictive modeling based on monitoring data collected during post-injection monitoring to demonstrate that CO₂ has been mineralized and/or dissolved, and lack of CO₂ migration in the formation that would present risk to water sources in the Area of Review. If supercritical CO₂ was injected the model must also investigate plume stability to ensure this.
- Modeling must be validated by comparison to historical monitoring data of subsurface pressure and operational/post-injection monitoring
- Models must utilize site specific geochemistry, CO₂ characteristics from analyses required in Section 3.1.3 of this module
- Models must assess the behavior and trapping of CO₂ for 50 years and demonstrate that there is no risk of migration beyond the AOR and it will not impact drinking water sources nor cause other environmental harms
- Comparison of model to predictions made at the time a site decommissioning plan was approved
For supercritical CO₂ injection, geophysical monitoring of the CO₂ plume may be performed to demonstrate limited change since the cessation of injection.
Or new methods as outlined in subsequent protocol (A document that describes how to quantitatively assess the net amount of CO₂ removed by a process. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the Carbon Fluxes involved in the CDR process. A Protocol measures the full carbon impact of a process against the Baseline of it not occurring.) versions and as measurement and monitoring technologies advance.

The timeframe for post injection monitoring should be aligned with regulatory guidance and based on site specific operation and monitoring data, for example 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.

3.3 Risk of Reversal

Based on present levels of scientific knowledge, projects applicable to this protocol are categorized as having a Very Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire. This is because there should be no reversals unless there is a loss of caprock or well integrity, and this technology does not yet have a documented history of reversals. There is, however, a risk of methane production within the reservoir, based on current literature, but this risk is very small²⁰. As a result, a 2% buffer pool (A common and recognized insurance mechanism among Registries allowing Credits to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.) will be set aside as a precaution. This reversal risk will be reassessed every 5 years, aligning with the crediting period, or when new scientific research and knowledge are produced.

Reversals will be accounted for by projects and the Isometric Registry (A database that holds information on Verified Removals and Reductions based on Protocols. Registries Issue Credits, and track their ownership and Retirement.) as detailed in Section 5.6 of the Isometric Standard.

3.3.1 Attribution of reversals

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

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:
- A reservoir has a total of 200t of material injected at the time when the reversal is detected (this information must be provided by the Operator).
- The Project Proponent has injected 50t of material in that reservoir.
- The amount of reversed CO₂ has been quantified to be 10t.
- The Project Proponent must compensate for 25% (50/200) of 10t CO₂ = 2.5t of CO₂.

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

3.4 Calculation of CO₂e_{MonitoringEmissions}

[math: CO_{2}e_{~~Monitoring~~Emissions}] is the total ~~quantity of~~ GHG (Those gaseous constituents of the atmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the spectrum of terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse ~~effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).)~~gas emissions ~~resulting from the operations and activities~~ associated with ~~monitoring the geologic storage of~~ CO2~~e (The amount of CO₂ emissions that would cause the same integrated radiative forcing or temperature change, over~~ a given ~~time~~Reporting ~~horizon, as an emitted amount of GHG or a mixture of GHGs. One common metric of CO₂e is the 100-year Global Warming Potential.)~~ ~~during the project operations, closure, and post closure periods. Emissions that occur during a reporting period~~Period, [math: RP] ~~are included directly~~.

Equations and ~~fully in that reporting period, and are not allocated across multiple reporting periods.~~

~~Emissions are calculated as:~~

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

~~Where~~

~~[math: CO_{2}e_{Monitoring}]~~ ~~= the total GHG~~ emissions ~~associated with storage monitoring allocated to a given~~ ~~[math: RP], in tonnes CO~~2e
~~[math: CO_{2}e_{Energy, Monitoring}]~~ ~~= the total GHG emissions associated with energy consumption for monitoring activities, in tonnes of CO~~2~~e, see~~ ~~Section 3.4.2~~.
~~[math: CO_{2}e_{Transportation, Monitoring}]~~ ~~= the total GHG emissions associated with transportation associated with monitoring activities, in tonnes of CO~~2~~e, see~~ ~~Section 3.4.3~~.
~~[math: CO_{2}e_{Embodied, Monitoring}]~~ ~~= the total GHG emissions associated with~~ ~~embodied emissions (Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.)~~ ~~from construction of monitoring equipment and facilities as well as use of consumables for monitoring activities, in tonnes of CO~~2~~e, see~~ ~~Section 3.4.4~~.
~~[math: CO_{2}e_{Misc., Monitoring}]~~ ~~the total miscellaneous GHG emission for a given RP, that cannot be catagorized by the above catagories.~~
~~[math: CO_{2}e_{Reversal}]= the total CO~~2~~e. See~~ ~~Risk of Reversal~~

3.4.1 Emission allocation to reporting periods

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

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

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

3.4.2 Calculation of CO2eEnergy, Monitoring

~~Emissions associated with CO~~2e~~Energy, monitoring~~ ~~are associated with electricity or fuel use during reporting period~~ ~~[math: RP]. Examples of electricity usage for monitoring activities may include, but are not limited to:~~

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

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

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

~~[Module: energy-use-accounting v1.0.0]~~
~~Refer to Energy Use Accounting Module for the calculation guidelines.~~

3.4.3 Calculation of CO2eTransportation, Monitoring

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

~~Transportation of samples for lab analysis~~
~~Transportation of specialty monitoring or sampling equipment to site~~

~~It should be noted that transportation emissions for monitoring will likely be zero or very low, as such emissions will typically be accounted for in fully burdened~~ ~~cradle to grave~~ ~~emissions factors for equipment used in monitoring. Project proponents should use caution and ensure~~ ~~double counting (Improperly allocating the same Removal or Reduction from a Project Proponent more than once to multiple Buyers.)~~ ~~is not occurring between embodied emissions and transportation emissions accounted for here.~~

~~[Module: transportation v1.0.0]~~
~~Refer to Transportation Emissions Accounting Module for the calculation guidelines.~~

3.4.4 Calculation of CO2eEmbodied, Monitoring

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

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

~~Process inputs or consumables:~~
~~Gasses, reagents or other materials used for operation of monitoring equipment, analytical testing, calibration of monitoring equipment and on-site analyzers~~
~~Water~~
~~Gasses such as nitrogen used for process or instrumentation purges~~
~~Consumable sampling equipment or supplies that are used in signifcant quantities~~
~~Equipment:~~
~~Monitoring wells and all associated materials (steel casing, concrete, etc.)~~
~~On-line analyzers, measurement equipment, or other such devices~~
~~Pumps, piping, and related equipment installed for monitoring purposes~~
~~All related support structures and infrastructure, including steel platforms, framing, supports, etc. installed for monitoring purposes~~
~~Buildings and associated equipment utilized for monitoring purposes (e.g., on-site laboratories)~~

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

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

3.4.5 Calculation of CO2eMisc. monitoring

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

~~The Project Proponent is responsible~~considerations for ~~identifying all sources of emissions directly or indirectly related to project~~monitoring activities, ~~and~~are ~~for~~set ~~reporting~~out ~~any outside of~~in the ~~categories~~relevant ~~provided~~protocol as ~~[math: CO_{2}e_{Misc.\ Monitoring}]~~.

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

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

3.4.6 Calculation of CO2eReversal

~~Calculation of CO~~2e~~Reversal~~ ~~is included~~repeated in ~~Equation~~this ~~1, but is covered seperately to the GHG assessment. See~~ ~~Risk of Reversal~~ ~~section~~module.

~~[Module: embodied-emissions v1.0.0]~~
~~Refer to Embodied Emissions Accounting Module for the calculation guidelines.~~

4.0 Closure Requirements

In order to decommission a site, the project proponent must prove beyond reasonable doubt that injected CO₂ will cause no harm to USDWs and stay within the AOR and thus CO₂ storage will be durable on geological timescales. The project proponent 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 project proponent, 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 module as when solubility/dissolution trapping has been confirmed the risk of release from the geological storage reservoir is negligible.

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 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 project proponent notifies other stakeholders (Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.), such as nearby drinking water utilities and agencies with primacy for drinking water regulations. A copy of the site decommissioning plan should also be retained by the project proponent for a minimum of 10 years (or longer if required by the regulator) following site decommissioning.

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

Within the EU, the site is transferred from the project proponent to a competent authority (i.e., national or local authorities) once 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.

4.1 Recordkeeping

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 project proponent for a minimum of 10 years after closure. These records must be available to be consulted by interested parties for future clarifications if needed.

5.0 Acknowledgements

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

Isometric would like to thank James Campbell, Ph.D. (Heriot-Watt University) for reviewing this module.

6.0 Definitions and Acronyms

: The amount of time carbon removed from the atmosphere by an intervention – for example, a CDR project – is expected to reside in a given Reservoir, taking into account both physical risks and socioeconomic constructs (such as contracts) to protect the Reservoir in question.
: Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.
: Describes the addition of carbon dioxide removed from the atmosphere to a reservoir, which serves as its ultimate destination. This is also referred to as “sequestration”.
: A location where carbon is stored. This can be via physical barriers (such as geological formations) or through partitioning based on chemical or biological processes (such as mineralization or photosynthesis).
: A calculation, series of calculations or simulations that use input variables in order to generate values for variables of interest that are not directly measured.
: An aquifer, or a portion of one, which supplies or has the possibility to supply any public water supply system, or drinking water for human consumption.
: The escape of CO₂ to the atmosphere after it has been stored, and after a Credit has been Issued. A Reversal is classified as avoidable if a Project Proponent has influence or control over it and it likely could have been averted through application of reasonable risk mitigation measures. Any other Reversals will be classified as unavoidable.
: ~~The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities~~.
: A body of similar rock type (e.g. color, grain size, mineral composition, texture) and a particular location in the stratigraphic column (vertical rock layers). Formations are large enough to be mappable on Earth's surface or traceable in the subsurface.
: An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.
: The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.
: A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.
: 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.
: 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).
: The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.
: Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.
: The period of time over which a Project Design Document is valid, and over which Removals or Reductions may be Verified, resulting in Issued Credits.
: Standard physical constants as well as standard values set forth by bodies such as the National Institute of Standards and Technology (NIST) or others.
: The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.
: A document that describes how to quantitatively assess the net amount of CO₂ removed by a process. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the Carbon Fluxes involved in the CDR process. A Protocol measures the full carbon impact of a process against the Baseline of it not occurring.
: A common and recognized insurance mechanism among Registries allowing Credits to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.
: A database that holds information on Verified Removals and Reductions based on Protocols. Registries Issue Credits, and track their ownership and Retirement.
: Those gaseous constituents of the atmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the spectrum of terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).
: The amount of CO₂ emissions that would cause the same integrated radiative forcing or temperature change, over a given time horizon, as an emitted amount of GHG or a mixture of GHGs. One common metric of CO₂e is the 100-year Global Warming Potential.
: ~~Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.~~
: ~~Improperly allocating the same Removal or Reduction from a Project Proponent more than once to multiple Buyers.~~
: Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.

7.0 Appendix 1: Monitoring Plan Requirements

This appendix details how the Project Proponent must monitor, document and report all metrics identified within this Module to demonstrate the durability of ~~carbon dioxide~~CO₂ removal. Following this guidance will ensure the Project Proponent measures and confirms ~~carbon dioxide~~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 crediting.

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

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 module
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	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Porosity & permeability	Porosity & permeability of sequestration zone strata and any impermeable layer	Pre Injection	Yes		As per permit requirements	Once		Permit or testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Reservoir volume	Sequestration zone of sufficient volume	Pre Injection	Yes		As per permit requirements	Once		Permit or testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Reactive surface area of target formation		Pre Injection	Yes			Once		Testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Reservoir injectivity	Sequestration zone of sufficient injectivity to receive the total anticipated volume of CO₂	Pre Injection	Yes		As per permit requirements	Once		Permit or testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
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	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
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	1 (CO₂ Storage via In-Situ Mineralization)
Formation fluid composition		Temperature formation fluid	Temperature of reservoir formation fluid	Pre Injection	Yes		Temperature sensor/probe	Pre-injection: Once	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2 (CO₂ Storage via In-Situ Mineralization)
pH formation fluid	pH of reservoir formation fluid prior to injection	Pre Injection, Operation & Post Injection	Yes		pH meter	Pre Injection: Once Operation: Weekly Post Injection: Monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Conductivity or other salinity measurement of formation fluid	Salinity of reservoir formation fluid prior to injection	Pre Injection, Operation & Post Injection	Yes		National/International approved method e.g., ASTM Designation D1125-82 or other	Pre Injection: Once Operation: Weekly Post Injection: Monthly	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	1, 3.1.3.2, 3.2 (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 or CH₄, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water)	Pre Injection, Operation & Post Injection	Yes	Set of tracers measured depends on project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.	Tracer dependent	Pre Injection: Once Operation: Weekly Post Injection: Monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Formation water density	Density of formation water	Pre Injection, Operation & Post Injection	Yes			Pre Injection: once Operation: 6 months Post Injection: 6 months	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Surface Elevation	Surface topography for baseline for elevation monitoring	SAR/InSAR		Pre Injection, Operation & Post Injection	Yes			Pre Injection: Once Operation:Quarterly Post Injection: Anuually	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Subsurface/subsurface tiltmeters				Pre Injection: Once Operation:Quarterly Post Injection: Anuually	As per manufacturer calibration procedure	Data logs/data acquisition system output
GPS Instruments				Pre Injection: Once Operation:Quarterly Post Injection: Anuually	As per manufacturer calibration procedure	Data logs/data acquisition system output
USDW composition	Geochemical composition of USDWs prior to injection	pH		Pre Injection, Operation & Post Injection	Yes		pH meter	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Temperature		Pre Injection, Operation & Post Injection	Yes		Temperature probe/sensor	Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output
Conductivity	Conductivity of the USDW	Pre Injection, Operation & Post Injection	Yes		National/International approved method e.g., ASTM Designation D1125-82 or other	Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output
Dissolved gas concentrations		Pre Injection, Operation & Post Injection	Yes		Gas chromatography	Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (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 or CH₄, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water)	Pre Injection, Operation & Post Injection	Under certain conditions	Set of tracers measured depends on project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.		Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output
Aquifer pressure	Pressure in the overlying aquifers			Pre Injection, Operation & Post Injection				Pre Injection: once Operation: continuous Post injection: monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Ecosystem imaging	Site based phenocams or medium-to-high resolution remote sensing to capture baseline			Pre Injection, Operation & Post Injection	Yes			Pre Injection: Once Operation: Annually Post-Injection: Annually	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Geophysical imaging	Geophysical survey to assess subsurface structure and provide baseline for future surveys			Pre Injection	Yes			Once	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2 (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			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	Yes		pH meter	Continuous	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	Continuous	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			Continuous	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)
Dissolved gas concentrations	Dissolved gas concentrations in CO₂ or in the water thst will dissolve the CO₂ within the wellbore	Operation	Under certain conditions	If dissolved CO₂ injection	Gas chromatography	Monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.1 (CO₂ Storage via In-Situ Mineralization)
Density of injecate	Calculated using the data from CO₂ and injection water	Pre-Injection & Operation	Under certain conditions	If dissolved CO₂ is injected		Pre Injection: Once Operation: Monthly			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 project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.		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 & Post Injection	Yes		As per permit requirements	Every 6 months	UIC permit, testing data		3.1.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
External mechanical integrity tests	Demonstration of external mechanical integrity			Operation & Post Injection	Yes		e.g., oxygen activation log, temperature log/sensor or noise log.	As per UIC permit requirements	UIC permit, testing data		3.1.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Pressure fall off test	Pressure fall off test			Operation & Post Injection	Yes		UIC or equivalent pressure falloff testing guidelines	Annually	Per testing protocol	Data logs/data acquisition system output	3.1.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Surface CO₂ concentrations	Determine CO₂ levels at the surface to help identify leaks	Surface gas concentrations	For example using optical CO₂ sensors, Eddy Covarianace, portable/stationary detectors, or inherent tracers	Pre Injection, Operation & Post Injection	Under certain conditions	When gas is detected and measurable		Pre Injection: once Operation:Monthly Post injection: 6 monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3, 3.2 (CO₂ Storage via In-Situ Mineralization)
CO₂ concentrations around wells		Operation & Post Injection	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, 3.2 (CO₂ Storage via In-Situ Mineralization)
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, Operation & Post Injection	Under certain conditions	If present	pH meter	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Temperature of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present	Temperature probe/sensor	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Density of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present		Pre Injection: Once Operation:Site dependent Post Injection: Site dependent			2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Conductivity of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present	National/International approved method e.g., ASTM Designation D1125-82 or other	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent		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, 3.2 (CO₂ Storage via In-Situ Mineralization)
Dissolved gas concentration of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present	Gas chromatography	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (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)	Pre Injection, Operation & Post Injection	Under certain conditions	If present. Set of tracers measured depends on project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.		Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Core analysis	analysis of core for evidence of mineralization			Post Injection	Not required but helpful						3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Seismic monitoring	Seismic monitoring			Operation & Post Injection	Under certain conditions	As per permit requirements	As per permit requirements	Continuous	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Reservoir pressure	Pressure within the reservoir, either measured at bottomhole or calculated using the wellhead pressure			Operation & Post Injection	Yes		Using pressure gauge or sensor	Continuous	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
reservoir temperature	Temperature within the targeted reservoir for mineralization			Operation & Post Injection	Yes		Temperature probe/sensor	Continuous	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Geophysical imaging	Indirect imaging of the reservoir to visualize migration			Operation & Post Injection	Under certain conditions	If supercritical CO₂ is injected		every 5 years or as per permit	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Hydrologic tests	Comparative hydrologic tests to identify changes in the reservoir hydraulic and/or storage characteristics attributed to injection			Operation & Post Injection	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 & Post Injection	Under certain conditions	Operation required				Model type, inputs and outputs	1, 2.2, 3.1.3.3, 3.2 (CO₂ Storage via In-Situ Mineralization)

8.0 Relevant Works

Footnotes

Snæbjörnsdóttir et al., 2020 https://doi.org/10.1038/s43017-019-0011-8 ↩
Matter et al., 2016 10.1126/science.aad8132 ↩↩² ↩³ ↩⁴
Clark et al., 2020 https://doi.org/10.1016/j.gca.2020.03.039 ↩
McGrail et al., 2017 https://doi.org/10.1016/j.egypro.2017.03.1716 ↩
White et al., 2020 https://dx.doi.org/10.1021/acs.est.0c05142 ↩↩²
Ratouis et al. 2022 https://doi.org/10.1016/j.ijggc.2022.103586 ↩
Tyne et al., 2021 https://doi.org/10.1038/s41586-021-04153-3 ↩↩²
Area of Review (AOR) means the area surrounding an injection well described according to the criteria set forth in § 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. ↩
Alfredsson et al., 2013 for Carbfix http://dx.doi.org/10.1016/j.ijggc.2012.11.019 ↩
Zakharova et al., 2012 for Wallula https://doi.org/10.1029/2012GC004305 ↩
Kelemen et al., 2011. https://doi.org/10.1146/annurev-earth-092010-152509 ↩
Thorsteinsson and Gunnarsson, 2014 https://publications.mygeoenergynow.org/grc/1033636.pdf ↩
Bubble Point Pressure is the pressure at which the first bubble of gas (including CO₂) forms when a liquid is depressurised. ↩
Carbfix Methodology https://carbfix.cdn.prismic.io/carbfix/038e79da-eb75-4379-9892-77c964dac751_Methdology+Carbfix_V1_2022_validated.pdf ↩↩²
Chen et al., 2019 Applied Energy ↩
Matter et al., 2014 https://doi.org/10.1016/j.egypro.2014.11.450 ↩
Cal. Code Regs., tit. 14, § 1724.14, “Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations,” (2017). ↩
McGrail et al 2017 https://doi.org/10.1016/j.egypro.2017.03.1716 ↩
Callow et al 2018 https://doi.org/10.1016/j.ijggc.2017.12.008 ↩
Tyne et al., 2023 https://doi.org/10.1021/acs.est.2c08652 ↩

1.0 Introduction

Redissolution of carbonates already precipitated as injection continues [risk A]
The injection of CO₂ will decrease the pH within the reservoir and potentially result in the dissolution of carbonates that have previously been mineralized. This CO₂ will be dissolved and thus more mobile than in carbonates. For supercritical CO₂ injection, the reservoir must have a confining layer to ensure that CO₂ will be contained and durably stored. For dissolved CO₂ injection, which is much less mobile, the reservoir will also ideally have a confining or impermeable layer, however where this is not present, further site charaterization and additional geochemical monitoring and pressure will be required. Furthermore, it is likely that this CO₂ will be remineralized downstream ensuring durbale storage ².
Mineralization causes a loss of permeability and/or decrease in pore space [risk B]
As mineralization occurs, injectivity to the storage reservoir could decrease due to a loss of permeability and pore space, particularly if mineralization occurs close to the injection wellhead. In this scenario, the reservoir capacity for CO₂ storage will decrease, but the durability of CO₂ that has already been injected and mineralized will not be impacted.
Formation of a gas phase [risk A, B]
Changes in reservoir pressure and temperature could result in the exsolution of some gaseous CO₂ [risk B].
CO₂ could be microbially consumed to form CH₄⁷ [risk A]. This risk is thought to be greater for supercritical CO₂ injection ⁷.
Indicators of CO₂ exsolution and biogas production should be monitored as part of the post-injection monitoring plan (see Section 3.2). Any gasses produced will be considered removed if one or more confining layers are present that prevent the vertical migration of buoyant phases. Any releases of gasses from the storage reservoir must be accounted for as reversals (The escape of CO₂ to the atmosphere after it has been stored, and after a Credit has been Issued. A Reversal is classified as avoidable if a Project Proponent has influence or control over it and it likely could have been averted through application of reasonable risk mitigation measures. Any other Reversals will be classified as unavoidable.) (see Section 3.3).
Induced seismicity can change reservoir properties [risk B]
The injection of CO₂ and water can induce seismicity within a reservoir which can alter the reservoir connectivity and flow paths. This risk may be a greater risk when injecting dissolved CO₂ due to the large volume of fluid that would need to be injected into the subsurface. Prior to any injection activity a site-specific study of the regional seismicity must be performed.
Predicted trapping rates are lower than predicted [risk A]
Mineralization within the reservoir could be less than initially predicted in reservoir models as a result of a limited supply of cations and/or reactive surface area. In this scenario, injected CO₂ would remain mobile either as a supercritical liquid or dissolved in water. As long as the reservoir has an impermeable confining layer or remains dissolved within the mineralization zone, CO₂ will be considered contained and durably stored. Any releases of this injected CO₂ from the storage reservoir must be accounted for (see Section 3.3).
For supercritical CO₂ dissolution rates may also be lower than initially predicted in reservoir models. In this scenario, injected CO₂ would remain mobile either as a supercritical liquid or gas phase. As long as the reservoir has an impermeable confining layer, CO₂ will be contained and durably stored. Any releases of this injected CO₂ from the storage reservoir must be accounted for (see Section 3.3).
Migration of free phase CO₂ outside of the intended formation [risk B]
For supercritical injection, the CO₂ plume will migrate within the reservoir and the injected plume could migrate further or have more limited dissolution than reservoir models initially predicted. 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.
Breach in well integrity leading to the leakage ~~(The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities.)~~ of CO₂ into the overlying formation. Injection, monitoring, and well integrity testing procedures should be updated during monitoring in order to ensure well integrity.
Migration of dissolved CO₂ into the overlying formation may also result in CO₂ exsolution due to the decreased hydrostatic head.

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

Table 1. See Section 2.2 for further details.

Parameter	Purpose
Reservoir lithology and mineralogy to ensure there are sufficient cations (CaO, MgO, FeO) which have not been altered	Input into reservoir models allowing for trapping mechanisms (e.g., mineralization and dissolution) predictions
Porosity, effective porosity, permeability, reactive surface area and volume of mineralization zone strata	Demonstrate the capacity and injectivity of the target formation to receive and safely store CO₂
Permeability and structural integrity of confining or impermeable layer	Demonstrate that any buoyant fluids or gasses will be trapped and unable to migrate upwards out of the reservoir
Temperature, pH, conductivity, density, composition of any tracers used and fluid saturation of geologic reservoir formation fluid/brine	For density and input into reservoir models which will guide injection and dissolution models for supercritical CO₂ injection
Concentration and δ¹³C signature of DIC and DOC as well as major and minor ion composition in formation fluid	Determine trapping mechanisms that may occur and for ~~leakage~~leak tracing if required
Surface elevation models, where applicable, which account for natural variation over a year.	Baseline for future measurements and allows inferences about pressure changes at depth.
Soil gas concentrations, where applicable	As a baseline for future measurements to determine if ~~leakage~~leaks isare occurring
Geochemical composition of USDWs within the Area of Review (AOR) (The area surrounding an injection well described according to the criteria set forth in the U.S. Code of Federal Regulations § 40 CFR.146.06, which, in some cases, such as Class II wells, the project area plus a circumscribing area the width of which is either 1⁄4 of a mile or a number calculated according to the criteria set forth in § 146.06.)⁸. This should include but is not limited to: pH, temperature, conductivity, major ions, dissolved gas concentrations and tracers (if using). Recommended additional measurements could include δ¹⁸O and δD of H₂O of the fluids, minor ions, density and δ¹³C of [DIC].	As a baseline for future measurements to determine if ~~leakage~~leaks isare occurring
Baseline ecosystem imaging, where applicable, using the combination of high-resolution aerial hyperspectral imaging and medium-resolution long-term data from Landsat sensors	As a baseline for future measurements to determine if ~~leakage~~leaks isare occurring

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, CO₂-water ratio (for dissolved CO₂ injection), 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 body.
Closure and Post-Closure Requirements: Requirements for proper closure of the storage reservoir and injection facility, as well as post closure requirements and post-injection monitoring to ensure CO₂ is mineralized and 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 geologic reservoir.

2.0 Permitting and Site Characterization

2.1 Permitting

2.2 Site Characterization and Feasibility Requirements

Includes a mineralization zone of sufficient volume, porosity, permeability, and injectivity to receive the total anticipated volume of the CO₂ and to facilitate CO₂ migration.
Has sufficient divalent cations (Mg, Ca, Fe) available for the CO₂ mineralization process within the mafic or ultramafic rocks, for example at Carbfix this number is ~25 wt%⁹ while in the Columbia River Basalts it is ~16 wt%¹⁰ and peridotites is >50 wt% ¹¹.
Has sufficient surface area for the reactions to take place, or a plan to engineer an increase in surface area to allow for the reactions.
For supercritical CO₂ injection, includes a confining system free of transmissive faults and fractures and of sufficient extent and thickness to contain the injected supercritical CO₂ and any gas generated if applicable. It should also allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s); the confining system 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;
For dissovled CO₂ injection, includes an impermeable layer (of sufficient thickness with a known and appropriate entry pressure and reactivity) and/or has sufficently characterised the mineralization zone and overlying lithologies (including permeability, reactivity and transmissive faults and fractures) to understand all possible fluid migration pathways that need to be monitored.
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 for example using the same or similar traffic light system as was designed for Reykjavik Energy¹².

Permits also ensure safety of USDWs. In order to ensure this, the project proponent must conduct a baseline characterization of the system, including but not limited to:

Surface elevation models
Soil gas composition incluidng CO₂, H₂ and CH₄, and fluxes over a period of a year to characterize any background spatial and temporal trends and variability.
Geochemical composition of USDWs and any natural springs connected to the mineralization zone or USDWs present within the AOR, to provide baseline measurements for which changes can be used to assess CO₂ leakage. This should include but is not limited:
temperature
pH
conductivity
major ions
dissolved gas concentrations (CO₂ impurities)
DIC concentrations
tracers (if using)
Baseline ecosystem imaging, where applicable.
Baseline geophysical surveys to characterize the reservoir. In addition, for supercritical CO₂ injection, in accordance with the agreed monitoring plan, geophysical surveys should be conducted during site characterization to create a baseline for which changes in the subsurface induced by the injection operation to be assessed.

2.3 Well Construction Requirements

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

3.0 Monitoring

3.1 Injection and Operational Monitoring Requirements

3.1.1 Injection and Injectant Operation & Monitoring

Maximum allowable surface injection pressure (MASIP) at the injection wellhead that is allowed during injection operations to prevent fracturing of the formation, set according to the regulators permit. Injection operation pressures must 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.
The pressure when the injected CO₂ stream enters the storage reservoir. This should be greater than the bubble point pressure¹³ of the dissolved CO₂ (under reservoir conditions). This is to ensure a reservoir pressure >5 bar higher than the bubble point pressure and enable immediate and complete solubility trapping of CO₂¹⁴ [A]. Reservoir pressure can either be measured at the bottom of the well or calculated using the hydrostatic pressure gradient for the AOR reservoir and water table depth.
Bubble point pressure must be calculated at least monthly, using appropriate geochemical tools (e.g., PHREEQC software version 3), thermodynamic databases and equations of state (e.g., Peng-Robinson). It must include consideration of the:
Mass flow rate of the CO₂ stream entering the injection well.
Mass flow rate of the water stream entering the injection well.
Temperature of the water stream entering the injection well.
Temperature of the CO₂ stream entering the injection well.
Elemental/gas/dissolved gas composition of the CO₂ stream entering the injection well.
Elemental composition of the water stream entering the injection well.
Maximum CO₂ injection rate to monitor volumes injected, prevent induced seismicity or return of injectant. In the case of dissolved CO₂ injection, this will also monitor the CO₂-water ratio (and the rate of each) to ensure all CO₂ dissolves. 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 (see Section 7.4.1.2 of the DAC protocol).
Monitoring and documentation of injection rate must be performed and records maintained for review. This should also be used to calculate the cumulative volume of CO₂ injected.
More information can be found within Section 7.4.1.4 of the relevant protocols.
Analysis of the CO₂ with sufficient frequency to yield data representative of its chemical and physical characteristics, using industry standard or indicated methods and quality and properly calibrated equipment [B]:
pH and temperature
CO₂ concentration (i.e., wt% CO₂, ~~carbon~~C content). More information on these measurements can be found in Sections 7.4.1.2 of the DAC protocol and 7.4.1.3 of the relevant protocols.
Gas/dissolved gas composition including impurities that might alter corrosivity, properties of the injectate downhole, or reactivity with the reservoir rocks/fluids (e.g., arsenic, hydrogen sulfide, mercury).
Density of dissolved CO₂
If dissolved CO₂ is being injected, major ions should, and [math: δ^{18}]O, [math: δ]D could, also be measured.

Additional measurments may include:

δ¹³C of the CO₂/DIC (if dissolved)
Use of tracers (added and/or inherent) when required. Reactive tracers could include [math: ^{14}]C and [math: δ^{13}]C, non-reactive tracers could include naphthalene sulfonates and noble gasses.
minor ions within dissolved CO₂ streams.

3.1.2 System Integrity Monitoring

A demonstration of internal mechanical integrity performed and reported every 6 months. This includes identifying any loss of mass, thickness, cracking, pitting, and 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 [B].
A demonstration of external mechanical integrity annually beginning 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 [B].
A pressure fall-off test, annually [B].

3.1.3 Migration, Trapping and Storage Reversal Monitoring

3.1.3.1 Near surface monitoring

CO₂ concentrations around the well head and personal CO₂ detector on all operators.
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:
- Optical CO₂ sensors, such as airborne infrared spectroscopy, non-dispersive infrared spectroscopy, cavity ring-down spectroscopy or LIDAR (light detection and ranging)
- Eddy covariance (EC) flux measurement at a specified height above the ground surface
- Portable or stationary carbon dioxide detectors
- Tracer testing using inherent tracers such as radon, noble gasses, and [math: δ^{13}]C of CO₂/CH₄, provide a unique fingerprint for the CO₂ or assocaited gases that can be identified in aboveground emissions .
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 addtion, fluids should be sampled for:
- pH
- Temperature
- Conductivity
- Major ions
- Dissolved gas concentrations
- DIC concentrations
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 gasses).
If using dissolved CO₂, water table and competing water usages should be monitored.
Identification of any natural springs connected to the mineralization formation or USDWs within the storage site, with baseline and annual monitoring to ensure no CO₂ leakage. This should include:
- pH
- Temperature
- Density
- Conductivity
- Dissolved gas concentrations
- DIC concentrations
Ecosystem stress, which can be an early indicator for CO₂ ~~leakage~~leaks. 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 images¹⁵.

3.1.3.2 Subsurface monitoring

Continuous measurements of reservoir temperature and pressure (which can be diagnostic of any reservoir mechanical failures) and periodic (6 monthly) measurement of formation water density (to determine the likelihood of clogging or decreases in injectivity). Measurement of in-situ fluid pressure that may be achieved using transducers placed within monitoring wells in the injection zone, behind casing gauges, or through direct measurement of fluid depth through a perforation.
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 tracer testing:
  Inherent tracers: Reservoir fluid sampling from the monitoring well(s) including but not limited to major ion, pH, temperature and DIC concentrations. DIC loss is expected along the flowpath from carbonate mineralization. This sampling should occur monthly unless the regulating permit requires more regular testing. Other inherent reactive tracers that could be used include [math: δ^{13}]C-CO₂/DIC, [math: δ^{44}]Ca and [math: δ]D and [math: δ^{18}]O of H₂O.
  Spiked tracers: Reactive tracers (e.g., [math: ^{14}]C) can also be added to the injected CO₂ stream. This should be performed following industry best practices. Spiked reactive tracers can lower uncertainties in any mass balance calculations, and may be required in systems where baseline DIC could not be determined, for example [math: ^{14}]C concentrations within the fluids would be very low compared to the injected concentrations.
  A comparison of the inherent or spiked pre- and post- injection can be used to quantify the amount of CO₂ dissolved and/or precipitated. For example, the amount of DIC loss compared to concentrations in the injected dissolved CO₂ can be used to quantify CO₂ mineralization².
- Non-reactive tracer testing:
  Non reactive tracers (e.g., noble gases) should be co-injected or measured if inherent with the CO₂ once the project has reached stable operation or within the first two years of injection (whichever occurs earlier or is most appropriate for the project, in line with findings from the Carbfix Project¹⁴) then sampled for in the monitoring well(s). Tracer tests should be performed according to industry best practices.
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^,¹⁶:
```
[math: \tag{Equation 1} [i]_{min}=X\cdot[i]_{is}+(1-X)\cdot[i]_{bf}-[i]_{meas}   ]
```
where [math: i] is the concentration of the reactive tracer (e.g., DIC, ¹⁴C), and [math: X] is the fraction of injectate relative to formation fluid present in the sample (calculated using non reactive tracers). The subscripts [math: min], [math: is], [math: bf] and [math: meas] refer to the amount mineralized, in the injectate, background reservoir fluid and measured during monitoring, respectively.
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.
- Gas concentrations (including CO₂, CH₄ and H₂) where free gas is present
Additional monitoring could include:
- Physical evidence and signatures of mineralization from the reservoir using drill cores.
- A seismic monitoring program may be suggested at the discretion of the UIC director or equivalent in areas of increased seismic risk, where demonstrated that seismicity may have an impact on the formation and the long duration storage of CO₂. This shall include deeper wireline or cemented subsurface geophones for microseismic monitoring and could be combined with at/near ground level stations as part of an intergrated strategy. The purpose of this is to determine the presence or absence of any induced micro-seismic activity associated with all wells and near any discontinuities, faults, or fractures in the subsurface, or any seismic activity in the area within the AOR of the injection facility and the area of the storage reservoir of magnitude 2.7 or greater [B].
If supercritical CO₂ is injected into the reservoir, additional subsurface monitoring requirements include [B]:
- Subsurface imaging may be required by the regulators. This includes reservoir imaging (seismic, gravity and/or electrical methods) and comparison to baseline conditions and reservoir models. This will allow the presence or absence of elevated pressure within the injection zone and the extent of the CO₂ plume to be tracked.
- Comparative hydrologic tests where required to identify changes in the reservoir hydraulic and/or storage characteristics attributed to injection⁵. This could include freshwater injection/recovery testing followed by a series of instantaneous pressurized slug/pulse withdrawal tests and wireline geophysical surveys. Results can be used within calibrated numerical models to quantify the amount of injected CO₂ that was mineralized.

3.1.3.3 Reservoir Modeling

3.1.3.4 LeakageCO₂ leakage

Halt injection while they identify the cause of this loss
Modify operations to increase dissolution/mineralization
Pause injection and monitor for dissolution/mineralization (this will likely be the case if solubility trapping is slower than expected), and /or
Update their monitoring plan and approve with the UIC director or equivalent

For CO₂ leakage, the project proponent is required to:

Halt injection while an assessment is conducted
Determine if the loss of containment can be repaired prior to injection beginning again
Quantify the amount of CO₂ lost

Observed and unexpected migration of the CO₂ plume which suggests potential movement of CO₂ outside the intended formation
CO₂ migration into a zone above the storage complex
CO₂ plume or elevated pressure extend beyond analytical model expectation because any of the following has occurred:
An seismic event of magnitude 2.7¹⁷ or greater within the AOR;
New site characterization data change the model inputs to such an extent that the predicted CO₂ fluid and/or pressure plume extends vertically or horizontally beyond what was originally predicted.

Further information on the risk and attribution of reversals Section 3.3 and Section 3.3.1.

3.2 Post-injection Monitoring Plan

Geochemical and/or tracer to demonstrate CO₂ mineralization, dissolution and 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 AOR.
Core studies to verify mineralization within the reservoir¹⁸^,¹⁹.
Utilize predictive modeling based on monitoring data collected during post-injection monitoring to demonstrate that CO₂ has been mineralized and/or dissolved, and lack of CO₂ migration in the formation that would present risk to water sources in the Area of Review. If supercritical CO₂ was injected the model must also investigate plume stability to ensure this.
Modeling must be validated by comparison to historical monitoring data of subsurface pressure and operational/post-injection monitoring
Models must utilize site specific geochemistry, CO₂ characteristics from analyses required in Section 3.1.3 of this module
Models must assess the behavior and trapping of CO₂ for 50 years and demonstrate that there is no risk of migration beyond the AOR and it will not impact drinking water sources nor cause other environmental harms
Comparison of model to predictions made at the time a site decommissioning plan was approved
For supercritical CO₂ injection, geophysical monitoring of the CO₂ plume may be performed to demonstrate limited change since the cessation of injection.
Or new methods as outlined in subsequent protocol (A document that describes how to quantitatively assess the net amount of CO₂ removed by a process. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the Carbon Fluxes involved in the CDR process. A Protocol measures the full carbon impact of a process against the Baseline of it not occurring.) versions and as measurement and monitoring technologies advance.

3.3 Risk of Reversal

3.3.1 Attribution of reversals

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

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:
- A reservoir has a total of 200t of material injected at the time when the reversal is detected (this information must be provided by the Operator).
- The Project Proponent has injected 50t of material in that reservoir.
- The amount of reversed CO₂ has been quantified to be 10t.
- The Project Proponent must compensate for 25% (50/200) of 10t CO₂ = 2.5t of CO₂.

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

3.4 Calculation of CO₂e_{MonitoringEmissions}

Equations and ~~fully in that reporting period, and are not allocated across multiple reporting periods.~~

~~Emissions are calculated as:~~

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

~~Where~~

~~[math: CO_{2}e_{Monitoring}]~~ ~~= the total GHG~~ emissions ~~associated with storage monitoring allocated to a given~~ ~~[math: RP], in tonnes CO~~2e
~~[math: CO_{2}e_{Energy, Monitoring}]~~ ~~= the total GHG emissions associated with energy consumption for monitoring activities, in tonnes of CO~~2~~e, see~~ ~~Section 3.4.2~~.
~~[math: CO_{2}e_{Transportation, Monitoring}]~~ ~~= the total GHG emissions associated with transportation associated with monitoring activities, in tonnes of CO~~2~~e, see~~ ~~Section 3.4.3~~.
~~[math: CO_{2}e_{Embodied, Monitoring}]~~ ~~= the total GHG emissions associated with~~ ~~embodied emissions (Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.)~~ ~~from construction of monitoring equipment and facilities as well as use of consumables for monitoring activities, in tonnes of CO~~2~~e, see~~ ~~Section 3.4.4~~.
~~[math: CO_{2}e_{Misc., Monitoring}]~~ ~~the total miscellaneous GHG emission for a given RP, that cannot be catagorized by the above catagories.~~
~~[math: CO_{2}e_{Reversal}]= the total CO~~2~~e. See~~ ~~Risk of Reversal~~

3.4.1 Emission allocation to reporting periods

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

3.4.2 Calculation of CO2eEnergy, Monitoring

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

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

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

~~[Module: energy-use-accounting v1.0.0]~~
~~Refer to Energy Use Accounting Module for the calculation guidelines.~~

3.4.3 Calculation of CO2eTransportation, Monitoring

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

~~Transportation of samples for lab analysis~~
~~Transportation of specialty monitoring or sampling equipment to site~~

~~[Module: transportation v1.0.0]~~
~~Refer to Transportation Emissions Accounting Module for the calculation guidelines.~~

3.4.4 Calculation of CO2eEmbodied, Monitoring

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

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

~~Process inputs or consumables:~~
~~Gasses, reagents or other materials used for operation of monitoring equipment, analytical testing, calibration of monitoring equipment and on-site analyzers~~
~~Water~~
~~Gasses such as nitrogen used for process or instrumentation purges~~
~~Consumable sampling equipment or supplies that are used in signifcant quantities~~
~~Equipment:~~
~~Monitoring wells and all associated materials (steel casing, concrete, etc.)~~
~~On-line analyzers, measurement equipment, or other such devices~~
~~Pumps, piping, and related equipment installed for monitoring purposes~~
~~All related support structures and infrastructure, including steel platforms, framing, supports, etc. installed for monitoring purposes~~
~~Buildings and associated equipment utilized for monitoring purposes (e.g., on-site laboratories)~~

3.4.5 Calculation of CO2eMisc. monitoring

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

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

3.4.6 Calculation of CO2eReversal

~~Calculation of CO~~2e~~Reversal~~ ~~is included~~repeated in ~~Equation~~this ~~1, but is covered seperately to the GHG assessment. See~~ ~~Risk of Reversal~~ ~~section~~module.

~~[Module: embodied-emissions v1.0.0]~~
~~Refer to Embodied Emissions Accounting Module for the calculation guidelines.~~

4.0 Closure Requirements

4.1 Recordkeeping

5.0 Acknowledgements

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

Isometric would like to thank James Campbell, Ph.D. (Heriot-Watt University) for reviewing this module.

6.0 Definitions and Acronyms

: The amount of time carbon removed from the atmosphere by an intervention – for example, a CDR project – is expected to reside in a given Reservoir, taking into account both physical risks and socioeconomic constructs (such as contracts) to protect the Reservoir in question.
: Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.
: Describes the addition of carbon dioxide removed from the atmosphere to a reservoir, which serves as its ultimate destination. This is also referred to as “sequestration”.
: A location where carbon is stored. This can be via physical barriers (such as geological formations) or through partitioning based on chemical or biological processes (such as mineralization or photosynthesis).
: A calculation, series of calculations or simulations that use input variables in order to generate values for variables of interest that are not directly measured.
: An aquifer, or a portion of one, which supplies or has the possibility to supply any public water supply system, or drinking water for human consumption.
: The escape of CO₂ to the atmosphere after it has been stored, and after a Credit has been Issued. A Reversal is classified as avoidable if a Project Proponent has influence or control over it and it likely could have been averted through application of reasonable risk mitigation measures. Any other Reversals will be classified as unavoidable.
: ~~The increase in GHG emissions outside the geographic or temporal boundary of a project that results from that project's activities~~.
: A body of similar rock type (e.g. color, grain size, mineral composition, texture) and a particular location in the stratigraphic column (vertical rock layers). Formations are large enough to be mappable on Earth's surface or traceable in the subsurface.
: An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.
: The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.
: A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.
: 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.
: 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).
: The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.
: Third-party auditing organizations that are experts in their sector and used to determine if a project conforms to the rules, regulations, and standards set out by a governing body. A VVB must be approved by Isometric prior to conducting validation and verification.
: The period of time over which a Project Design Document is valid, and over which Removals or Reductions may be Verified, resulting in Issued Credits.
: Standard physical constants as well as standard values set forth by bodies such as the National Institute of Standards and Technology (NIST) or others.
: The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.
: A document that describes how to quantitatively assess the net amount of CO₂ removed by a process. To Isometric, a Protocol is specific to a Project Proponent's process and comprised of Modules representing the Carbon Fluxes involved in the CDR process. A Protocol measures the full carbon impact of a process against the Baseline of it not occurring.
: A common and recognized insurance mechanism among Registries allowing Credits to be set aside (in this case by Isometric) to compensate for Reversals which may occur in the future.
: A database that holds information on Verified Removals and Reductions based on Protocols. Registries Issue Credits, and track their ownership and Retirement.
: Those gaseous constituents of the atmosphere, both natural and anthropogenic (human-caused), that absorb and emit radiation at specific wavelengths within the spectrum of terrestrial radiation emitted by the Earth’s surface, by the atmosphere itself, and by clouds. This property causes the greenhouse effect, whereby heat is trapped in Earth’s atmosphere (CDR Primer, 2022).
: The amount of CO₂ emissions that would cause the same integrated radiative forcing or temperature change, over a given time horizon, as an emitted amount of GHG or a mixture of GHGs. One common metric of CO₂e is the 100-year Global Warming Potential.
: ~~Life cycle GHG emissions associated with production of materials, transportation, and construction or other processes for goods or buildings.~~
: ~~Improperly allocating the same Removal or Reduction from a Project Proponent more than once to multiple Buyers.~~
: Any person or entity who can potentially affect or be affected by Isometric or an individual Project activity.

7.0 Appendix 1: Monitoring Plan Requirements

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 module
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	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Porosity & permeability	Porosity & permeability of sequestration zone strata and any impermeable layer	Pre Injection	Yes		As per permit requirements	Once		Permit or testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Reservoir volume	Sequestration zone of sufficient volume	Pre Injection	Yes		As per permit requirements	Once		Permit or testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Reactive surface area of target formation		Pre Injection	Yes			Once		Testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
Reservoir injectivity	Sequestration zone of sufficient injectivity to receive the total anticipated volume of CO₂	Pre Injection	Yes		As per permit requirements	Once		Permit or testing data	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
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	1, 2.2 (CO₂ Storage via In-Situ Mineralization)
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	1 (CO₂ Storage via In-Situ Mineralization)
Formation fluid composition		Temperature formation fluid	Temperature of reservoir formation fluid	Pre Injection	Yes		Temperature sensor/probe	Pre-injection: Once	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2 (CO₂ Storage via In-Situ Mineralization)
pH formation fluid	pH of reservoir formation fluid prior to injection	Pre Injection, Operation & Post Injection	Yes		pH meter	Pre Injection: Once Operation: Weekly Post Injection: Monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Conductivity or other salinity measurement of formation fluid	Salinity of reservoir formation fluid prior to injection	Pre Injection, Operation & Post Injection	Yes		National/International approved method e.g., ASTM Designation D1125-82 or other	Pre Injection: Once Operation: Weekly Post Injection: Monthly	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	1, 3.1.3.2, 3.2 (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 or CH₄, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water)	Pre Injection, Operation & Post Injection	Yes	Set of tracers measured depends on project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.	Tracer dependent	Pre Injection: Once Operation: Weekly Post Injection: Monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Formation water density	Density of formation water	Pre Injection, Operation & Post Injection	Yes			Pre Injection: once Operation: 6 months Post Injection: 6 months	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Surface Elevation	Surface topography for baseline for elevation monitoring	SAR/InSAR		Pre Injection, Operation & Post Injection	Yes			Pre Injection: Once Operation:Quarterly Post Injection: Anuually	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Subsurface/subsurface tiltmeters				Pre Injection: Once Operation:Quarterly Post Injection: Anuually	As per manufacturer calibration procedure	Data logs/data acquisition system output
GPS Instruments				Pre Injection: Once Operation:Quarterly Post Injection: Anuually	As per manufacturer calibration procedure	Data logs/data acquisition system output
USDW composition	Geochemical composition of USDWs prior to injection	pH		Pre Injection, Operation & Post Injection	Yes		pH meter	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Temperature		Pre Injection, Operation & Post Injection	Yes		Temperature probe/sensor	Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output
Conductivity	Conductivity of the USDW	Pre Injection, Operation & Post Injection	Yes		National/International approved method e.g., ASTM Designation D1125-82 or other	Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output
Dissolved gas concentrations		Pre Injection, Operation & Post Injection	Yes		Gas chromatography	Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (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 or CH₄, major or minor ions, radiocarbon (spiked reactive), and non reactive tracers (e.g., noble gases, stable isotopes of water)	Pre Injection, Operation & Post Injection	Under certain conditions	Set of tracers measured depends on project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.		Pre Injection: Once Operation: Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output
Aquifer pressure	Pressure in the overlying aquifers			Pre Injection, Operation & Post Injection				Pre Injection: once Operation: continuous Post injection: monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Ecosystem imaging	Site based phenocams or medium-to-high resolution remote sensing to capture baseline			Pre Injection, Operation & Post Injection	Yes			Pre Injection: Once Operation: Annually Post-Injection: Annually	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Geophysical imaging	Geophysical survey to assess subsurface structure and provide baseline for future surveys			Pre Injection	Yes			Once	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2 (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			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	Yes		pH meter	Continuous	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	Continuous	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			Continuous	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)
Dissolved gas concentrations	Dissolved gas concentrations in CO₂ or in the water thst will dissolve the CO₂ within the wellbore	Operation	Under certain conditions	If dissolved CO₂ injection	Gas chromatography	Monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.1 (CO₂ Storage via In-Situ Mineralization)
Density of injecate	Calculated using the data from CO₂ and injection water	Pre-Injection & Operation	Under certain conditions	If dissolved CO₂ is injected		Pre Injection: Once Operation: Monthly			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 project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.		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 & Post Injection	Yes		As per permit requirements	Every 6 months	UIC permit, testing data		3.1.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
External mechanical integrity tests	Demonstration of external mechanical integrity			Operation & Post Injection	Yes		e.g., oxygen activation log, temperature log/sensor or noise log.	As per UIC permit requirements	UIC permit, testing data		3.1.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Pressure fall off test	Pressure fall off test			Operation & Post Injection	Yes		UIC or equivalent pressure falloff testing guidelines	Annually	Per testing protocol	Data logs/data acquisition system output	3.1.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Surface CO₂ concentrations	Determine CO₂ levels at the surface to help identify leaks	Surface gas concentrations	For example using optical CO₂ sensors, Eddy Covarianace, portable/stationary detectors, or inherent tracers	Pre Injection, Operation & Post Injection	Under certain conditions	When gas is detected and measurable		Pre Injection: once Operation:Monthly Post injection: 6 monthly	As per manufacturer calibration procedure	Data logs/data acquisition system output	1, 2.2, 3.1.3, 3.2 (CO₂ Storage via In-Situ Mineralization)
CO₂ concentrations around wells		Operation & Post Injection	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, 3.2 (CO₂ Storage via In-Situ Mineralization)
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, Operation & Post Injection	Under certain conditions	If present	pH meter	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Temperature of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present	Temperature probe/sensor	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Density of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present		Pre Injection: Once Operation:Site dependent Post Injection: Site dependent			2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Conductivity of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present	National/International approved method e.g., ASTM Designation D1125-82 or other	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent		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, 3.2 (CO₂ Storage via In-Situ Mineralization)
Dissolved gas concentration of natural springs		Pre Injection, Operation & Post Injection	Under certain conditions	If present	Gas chromatography	Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (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)	Pre Injection, Operation & Post Injection	Under certain conditions	If present. Set of tracers measured depends on project. This must include at least one reactive and unreactive tracer. DIC and major ions are required.		Pre Injection: Once Operation:Site dependent Post Injection: Site dependent	As per manufacturer calibration procedure	Data logs/data acquisition system output	2.2, 3.1.3.1, 3.2 (CO₂ Storage via In-Situ Mineralization)
Core analysis	analysis of core for evidence of mineralization			Post Injection	Not required but helpful						3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Seismic monitoring	Seismic monitoring			Operation & Post Injection	Under certain conditions	As per permit requirements	As per permit requirements	Continuous	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Reservoir pressure	Pressure within the reservoir, either measured at bottomhole or calculated using the wellhead pressure			Operation & Post Injection	Yes		Using pressure gauge or sensor	Continuous	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
reservoir temperature	Temperature within the targeted reservoir for mineralization			Operation & Post Injection	Yes		Temperature probe/sensor	Continuous	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Geophysical imaging	Indirect imaging of the reservoir to visualize migration			Operation & Post Injection	Under certain conditions	If supercritical CO₂ is injected		every 5 years or as per permit	As per manufacturer calibration procedure	Data logs/data acquisition system output	3.1.3.2, 3.2 (CO₂ Storage via In-Situ Mineralization)
Hydrologic tests	Comparative hydrologic tests to identify changes in the reservoir hydraulic and/or storage characteristics attributed to injection			Operation & Post Injection	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 & Post Injection	Under certain conditions	Operation required				Model type, inputs and outputs	1, 2.2, 3.1.3.3, 3.2 (CO₂ Storage via In-Situ Mineralization)

8.0 Relevant Works

Footnotes

Snæbjörnsdóttir et al., 2020 https://doi.org/10.1038/s43017-019-0011-8 ↩
Matter et al., 2016 10.1126/science.aad8132 ↩↩² ↩³ ↩⁴
Clark et al., 2020 https://doi.org/10.1016/j.gca.2020.03.039 ↩
McGrail et al., 2017 https://doi.org/10.1016/j.egypro.2017.03.1716 ↩
White et al., 2020 https://dx.doi.org/10.1021/acs.est.0c05142 ↩↩²
Ratouis et al. 2022 https://doi.org/10.1016/j.ijggc.2022.103586 ↩
Tyne et al., 2021 https://doi.org/10.1038/s41586-021-04153-3 ↩↩²
Area of Review (AOR) means the area surrounding an injection well described according to the criteria set forth in § 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. ↩
Alfredsson et al., 2013 for Carbfix http://dx.doi.org/10.1016/j.ijggc.2012.11.019 ↩
Zakharova et al., 2012 for Wallula https://doi.org/10.1029/2012GC004305 ↩
Kelemen et al., 2011. https://doi.org/10.1146/annurev-earth-092010-152509 ↩
Thorsteinsson and Gunnarsson, 2014 https://publications.mygeoenergynow.org/grc/1033636.pdf ↩
Bubble Point Pressure is the pressure at which the first bubble of gas (including CO₂) forms when a liquid is depressurised. ↩
Carbfix Methodology https://carbfix.cdn.prismic.io/carbfix/038e79da-eb75-4379-9892-77c964dac751_Methdology+Carbfix_V1_2022_validated.pdf ↩↩²
Chen et al., 2019 Applied Energy ↩
Matter et al., 2014 https://doi.org/10.1016/j.egypro.2014.11.450 ↩
Cal. Code Regs., tit. 14, § 1724.14, “Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations,” (2017). ↩
McGrail et al 2017 https://doi.org/10.1016/j.egypro.2017.03.1716 ↩
Callow et al 2018 https://doi.org/10.1016/j.ijggc.2017.12.008 ↩
Tyne et al., 2023 https://doi.org/10.1021/acs.est.2c08652 ↩

1.0 Introduction

2.0 Permitting and Site Characterization

2.1 Permitting

2.2 Site Characterization and Feasibility Requirements

2.3 Well Construction Requirements

3.0 Monitoring

3.1 Injection and Operational Monitoring Requirements

3.1.1 Injection and Injectant Operation & Monitoring

3.1.2 System Integrity Monitoring

3.1.3 Migration, Trapping and Storage Reversal Monitoring

3.1.3.1 Near surface monitoring

3.1.3.2 Subsurface monitoring

3.1.3.3 Reservoir Modeling

3.1.3.4 LeakageCO2 leakage

3.2 Post-injection Monitoring Plan

3.3 Risk of Reversal

3.3.1 Attribution of reversals

3.4 Calculation of CO2e MonitoringEmissions

3.4.1 Emission allocation to reporting periods

3.4.2 Calculation of CO2eEnergy, Monitoring

3.4.3 Calculation of CO2eTransportation, Monitoring

3.4.4 Calculation of CO2eEmbodied, Monitoring

3.4.5 Calculation of CO2eMisc. monitoring

3.4.6 Calculation of CO2eReversal

4.0 Closure Requirements

4.1 Recordkeeping

5.0 Acknowledgements

6.0 Definitions and Acronyms

7.0 Appendix 1: Monitoring Plan Requirements

8.0 Relevant Works

Footnotes

1.0 Introduction

2.0 Permitting and Site Characterization

2.1 Permitting

2.2 Site Characterization and Feasibility Requirements

2.3 Well Construction Requirements

3.0 Monitoring

3.1 Injection and Operational Monitoring Requirements

3.1.1 Injection and Injectant Operation & Monitoring

3.1.2 System Integrity Monitoring

3.1.3 Migration, Trapping and Storage Reversal Monitoring

3.1.3.1 Near surface monitoring

3.1.3.2 Subsurface monitoring

3.1.3.3 Reservoir Modeling

3.1.3.4 LeakageCO2 leakage

3.2 Post-injection Monitoring Plan

3.3 Risk of Reversal

3.3.1 Attribution of reversals

3.4 Calculation of CO2e MonitoringEmissions

3.4.1 Emission allocation to reporting periods

3.4.2 Calculation of CO2eEnergy, Monitoring

3.4.3 Calculation of CO2eTransportation, Monitoring

3.4.4 Calculation of CO2eEmbodied, Monitoring

3.4.5 Calculation of CO2eMisc. monitoring

3.4.6 Calculation of CO2eReversal

4.0 Closure Requirements

4.1 Recordkeeping

5.0 Acknowledgements

6.0 Definitions and Acronyms

7.0 Appendix 1: Monitoring Plan Requirements

8.0 Relevant Works

Footnotes

3.1.3.4 LeakageCO₂ leakage

3.4 Calculation of CO₂e_{MonitoringEmissions}

3.1.3.4 LeakageCO₂ leakage

3.4 Calculation of CO₂e_{MonitoringEmissions}