CO₂ Storage in Depleted Hydrocarbon Reservoirs
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This Module details durability and monitoring requirements for storage of CO2 removed from the atmosphere and stored in depleted hydrocarbon fields.
CO2 can be injected into depleted hydrocarbon fields as a gas, supercritical fluid, dissolved in water or, in exceptional circumstances, liquid CO2. The behavior of CO2 in the reservoir (i.e., trapping mechanisms) will depend on the injected phase, formation water chemistry, composition and amount of hydrocarbons present and the type of reservoir the CO2 is injected into (i.e., siliclastic vs carbonate vs volcanogenic sandstones). To ensure sufficient durability, CO2 characteristics and the conditions within the storage reservoir must be well defined, modeled and monitored.
Within depleted hydrocarbon fields, injected CO2 is prevented from vertically migrating by structural or stratigraphic barriers such as low permeability confining layer (i.e., caprocks) (such as anhydrite or shale) or structural features (such as faults). This method of containment of CO2 is known as physic§alphysical trapping. CO2 can also become trapped within the pore space of the reservoir preventing its migration as CO2 is held in-place, this is known as residual trapping. Through time, physically trapped CO2 will become chemically trapped, eliminating its inherent buoyancy and associated risk of mobility. One type of chemical trapping is by dissolution (solubility trapping) into the formation waters which increases the density of injected CO2, meaning it will sink in a reservoir. Mineral trapping (another form of chemical trapping) removes dissolved CO2 from fluids and permanently immobilizes injected carbon dioxide in solid carbonate minerals. The reduction of CO2 mobility through these subsequent chemical trapping mechanisms reduces the risk of reversibility associated with breaks in the seal. Once CO2 is trapped within the reservoir and there is proof of no migration outside the target reservoir or to Underground Sources of Drinking Water (USDWs) after closure (as per regulating permitting requirements) within the Area of Review (AOR), the CO2 can be considered geologically sequestered.
This Module is applicable for gaseous, supercritical and water-dissolved CO2 injections into depleted hydrocarbon fields within permeable sedimentary systems (such as siliclastic sandstones, carbonates and volcanogenic sandstones).
This section outlines requirements for evaluating CO2 injection and storage within depleted hydrocarbon fields, with a focus on site characterization, construction and monitoring. The post-injection monitoring plan detailed in Section 3.2 acts to address and mitigate these potential risks to durability. Section 34.30 addresses accounting for any emissions associated with these risks.
Monitoring of the injection site needs to be completed to ensure that any injected CO2 remains stored within the confines of the storage reservoir and does not migrate outside of the targeted formation, nor converted into gases that may later be re-emitted (e.g., CO2, CH4). The injection site shall be monitored in accordance with this ModuleModules and the country/region specific well permitting requirements as specified in the operating permit for the injection site issued. Each site should create a “testing and monitoring plan” which incorporates available, site-specific techniques that support the overall goals of detecting trends or events that might lead to endangerment of USDWs and demonstrates that the Project is operating as permitted. This plan should be submitted to Isometric.
The subsurface monitoring approach developed and implemented by the Project Proponent shall address the following, via the permitting process and permit compliance, or by additional efforts and documentation.
The subsurface monitoring approach developed and implemented by the Project Proponent shall address the following, via the permitting process and permit compliance, or by additional efforts and documentation.
Specifically, the following requirements must be met to ensure durable storage of CO2 in the storage reservoir.
Potential risks to expected durability are site specific, but generally fall under four categories: CO2 mobility [risk A], pressure changes [risk B], chemical changes [risk C] and well integrity [risk D]. Specific risks may include:
Projects must submit at least one address and/or specific geo-coordinates for the project. Projects may submit multiple project locations - please specify the operations occurring at each project location.
[/R-CWVK-0]The injection site must have a current well permit issued by the responsible authority for the location of the injection facility and reservoir. The permit must specifically identify CO2 as an acceptable injectantsinjectant under the permit. In addition, theThe Project must comply with all applicable local environmental, ecological and social requirements as well as those set out in the relevant Protocol and the Environmental and Social Impacts Section 3.7 of the Isometric Standard. ReservoirsIf maythere notis a possibility that the reservoir could be utilizedimpacted ifby enhanced hydrocarbon recovery (EHR or EHR+) activitiesor areother occurringproduction withinoperations, thestorage fieldwill not be permitted.
Projects operating with an approved permitting regime (see Appendix 2) should comply with the requirements of this Module and of the permit. Where monitoring parameters in this Module defer to the permit, the permit requirements must be disclosed to Isometric within the Project Design Document (PDD) and followed throughout The Project. Permit compliance can only be used as evidence for requirements that align with this Module and have permit compliance as an evidence option. If a requirement does not allow permit compliance as evidence, the Projectrequired evidence must be submitted.
For projects operating in locations outside of these permitting regimes, the Project Proponent must ensure that they meet the requirements of this Module and are equally as rigorous as the permits listed above. This monitoring plan must be signed off by a licensed geoscience professional (Professional Geologist (PG/P.Geo), Chartered Geologist (CGeol), European Geologist (EurGeol), or equivalent; suitably experienced in subsurface work and/or in CO2 storage (or analogous saline/gas storage). The sign-off is to confirm the plan is sufficient for the site, and the signed report must be submitted to Isometric as part of the PDD. Specifically, the reviewer should sign off on: (1) site characterization report; (2) Area of Review (AOR) and reservoir modeling with uncertainty; (3) risk register and mitigation plan; (4) Monitoring/Testing/Reporting plan; (5) well-integrity plan; (6) demonstration of rigor equivalent to the listed permits; and (7) CO2 Storage Resources Management System (SRMS) maturity opinion.
[/G-All Projects are required to clearly report the regulations for which are utilized at the site, with any deviations from the relevant national/international standards outlined within the PDD upon submission to the relevant validation & verification body (VVB).
[/G-PMJ6-0]For Projects with an Approved Permitting Regime and in good standing with the permitting authority, monitoring requirements which identify "Approved Permit" under Evidence Reporting (see Monitoring Requirement Tables in Appendix 1) may be satisfied through submissions to the permitting authority.
The Storage Operator must maintain copies of all data and evidence submitted to the permitting authority against these requirements and must provide such records to Isometric and the VVB within 30 days of submission to the permitting authority, or upon request.
For monitoring requirements not covered under the Approved Permit, the Project Proponent remains responsible for collecting and reporting all required data directly to Isometric and the VVB according to the frequencies and standard reporting timelines specified in this module.
In the case of changes to the permit requirements, permitting authority, and/or regulatory environment, the Project Proponent must notify Isometric and the VVB immediately of any changes which may impact monitoring requirements. Monitoring plans will be subject to reevaluation following such changes.
Site characterizationscharacterization must include evaluation of reservoir chemistry (both rock and fluids) and conditions where required to ensure CO2 will be stored within the reservoir. The permit shall define the AOR for the site in accordance with the requirements for the specific well class, formation, and local characteristics.
As part of the permit application, the Project Proponent must demonstrate and justify that the CO2 and injection process result in long term stability and limited lateral migration such that the CO2 stays within the target formation and does not impact the USDWs or above-surface environmental conditions. The Project Proponent must demonstrate the geologic system:
In addition, characterization of site geology and geochemistry, potential interaction of the injected CO2 and in-situ residual hydrocarbons or other fluids and injectant mobility and reservoir simulations will be required.
The Project Proponent must conduct a baseline characterization of the AOR assessing parameters that include but are not limited to those set out in Table 1.
Table 1: List of baseline characterization requirements
Parameter | Purpose |
|---|---|
Reservoir lithology and mineralogy | Input into reservoir models allowing for trapping mechanism predictions. Onsite characterization may include drilling, coring or logging. |
Porosity, permeability and volume of sequestration zone strata | Demonstrate the capacity and injectivity of the target formation to receive and safely store CO2. |
Permeability and structural integrity of confining layer/cap rock | Demonstrate that any buoyant fluids or gases will be trapped and unable to migrate upwards out of the reservoir. |
Maximum allowable surface injection pressure | Surface injection pressure at the injection wellhead that is allowed during injection operations to prevent fracturing of the formation, set according to the regulators permit. |
Temperature, pH, salinity/conductivity and fluid saturation of storage reservoir formation fluid/brine | For density calculations and inputs into reservoir models which will guide injection. |
Overlying formation pressure | Baseline overlying formation pressure to monitor for CO2 leaks or caprock failure. |
Composition of residual hydrocarbons | For determining potential interactions, and for modeling mixing and migration. |
Dissolved gas, including of DIC, composition in formation fluids and composition of any tracers being used (e.g., δ13C signature and/or major and minor ion) | To determine the trapping mechanisms that may occur and for |
Surface elevation models, where applicable, which account for natural variation over a year | As a baseline for future measurements and allows inferences about pressure changes at depth. |
Surface/seafloor gas concentrations, where applicable | Measurements should be taken over a year to act as a baseline spatial and temporal trends and variability for future measurements to determine if CO2 leaks are occurring. |
Baseline geophysical surveys, where applicable | A baseline |
Geochemical composition of USDWs within the AOR (where required in the permit) this should include but is not limited to pH, temperature, density, conductivity, total dissolved solids and dissolved gas concentrations | As a baseline for future measurements to determine if CO2 leaks are occurring. |
Baseline ecosystem imaging, where applicable | As a baseline for future measurements to determine if CO2 leaks are occurring. |
Baseline surface elevation, where applicable | As a baseline for future measurements to help determine if CO2 leaks are occurring. |
Baseline surface CO2 fluxes, where applicable | As a baseline for future measurements to determine if CO2 leaks are occurring. |
Long-term stability justification must be completed in conjunction with performance monitoring of the formation, such as pressure front monitoring, to ensure fracturing and resulting mobility are not occurring. Specific laboratory core analysis experiments with relevant cores could be conducted to confirm suitability for CO2 sequestration operations, including quantification of CO2 reactivity with the core, especially with regards to reductions in permeability and secondary trapping mechanisms (residual, solubility and mineral trapping). The laboratory experiments may also include quantification of the rate at which CO2 migrates, dissolves in water or precipitates as carbonate minerals. A relevant core would ideally be a core directly sampled from the Projectproject site.
Site characterizations and analytical modeling shall be reviewed every 5 years as part of the regulators permit renewal application minimum, or at the Regulators Programs Director’s request, or when monitoring and operational conditions warrant, as indicated by a significant change in site conditions or injectant characteristics, based on monitoring data. The review shall include a comparison of pre-injection Project assumptions and reservoir models to actual measured conditions including plume size, extent, and migration, where possible, and specific operating conditions observed during injection. Estimates revised with any acquired monitoring data should demonstrate that the planned injection volume will remain within the storage complex until the end of the post-injection monitoring period.
Project validation and verification must incorporate site visits to project facilities in accordance with the requirements of ISO 14064-3, 6.1.4.2, including, at minimum, site visits during validationthe andfirst initialValidation verificationor Verification of a Project, to the capture and (if applicable) storage site. Verifiers (i.e., VVBs) should whenever possible observe operation of the capture and storage processes to ensure full documentation of process inputs and outputs through visual observation and validation of instrumentation, measurements, and required data quality measures.
A site visit must thereafter occur at least once every 2 years atduring each locationproject validation. Additional site visits may be required if there are substantial changes to field operations over the course of a project's validation period, or if deemed necessary by Isometric or the VVB. Site visit plans are to be determined according to the VVB's internal assessment, in consultation with Isometric.
The Project Proponent must ensure that the injection well is constructed in compliance with the regulators permit and documentation and records of well construction are maintained and available for review.
[/R-At a minimum, the Project Proponent must ensure that all injection, observation or monitoring, legacy offset and production wells contained within the delineated AOR have been evaluated. This will help address risk [D]. Extra caution should be used on wells which penetrate the confining layers. Wells which pose a risk to durability must be plugged prior to injection in order to:
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 theThe Project.
All surface casing will be set below the lowermost USDW and cemented to the surface. All well materials must be compatible with fluids with which the materials may be expected to come into contact, including CO2 and formation fluids (e.g., corrosion-resistant well casings and CO2 resistant cement) and must meet or exceed standards developed for such materials by API, ASTM International, or comparable standards.
[/G-XY9G-0]The casing and cementing program must be designed to prevent the movement of fluids out of the sequestration zone and above the storage complex.
[/Monitoring of injection, system integrity as well as for subsurface migration is required in order to identify and measure potential leaks and/or validate update models as appropriate.
The Project Proponent will ensure that the injection facility complies with the well permit, including the development and implementation of the well operating plan as required by the permit.
If the permit (for Projects within an approved permitting jurisdiction) or approved monitoring plan (for those outside of these jurisdictions) has different monitoring requirements to those stated here, please provide justification of any deviation within the PDD.
This plan should be updated every five years, unless the regulatory body that issues the permit requires this to be updated more often, to take account of changes to the assessed risk of leakageCO2 leaks, changes to the assessed risks to the environment and human health, new scientific knowledge, and improvements in best available technology. The risks (risksSection 1.0) addressed by each measurement are denoted in square brackets. At a minimum, the permit and associated well operating plan willshall consider the following:
Wells must have species-specific gas detectors (or equivalent sensors/imaging) capable of detecting, at minimum, CO₂, CH₄ and C3H8, with alarms and injection shut-off systems (e.g., automatic shut-off or procedures in place for manual shut off of injection/operation), including, at a minimum, injection pump shutoff when maximum pressure is reached or maximum flow rate is exceeded. Where site-specific risk assessment identifies additional species of concern (e.g., H₂S, VOCs, other hydrocarbons), detection capability for those species must also be provided. The Project Proponent must justify the selected detector type(s) and monitoringtheir suitability for athe gaseoussite releaseconditions (CO2,in hydrocarbonsthe PDD [C].
Detectors/alarms may be placed on the injection wellhead or othera GHGsmonitoring well. If gas is detected, continuous detection must be established at the wellhead and any producing or monitoring wells. The determination that detected gas is attributable to project operations must be made by the Project Proponent and reported to Isometric and the VVB [C].
If gas detection alarms are activated at any monitored well, a Triggered Gas Investigation is initiated (Section 3.1.3.1). IfThe activated the operatorOperator must immediately investigate and identify as expeditiously as possible (or in accordance with permit requirements) the cause of the alarm or shutoff, and report the instance to the Isometric. Where a Triggered Gas Investigation (Section 3.1.3.3) is already active, individual alarm events must be logged and reported but do not require a separate investigation unless they indicate a materially different or escalating condition [C].
As applicable based on specific site conditions, formation type, and permit class, monitoring is to ensure CO2 migration beyond the AOR within the target reservoir has not occurred. Changes versus baseline conditions and/or modeled behavior/predictions may indicate CO2 related migration or irregularities. These should be used to assess whether any corrective measurements are taken and used to make an updated assessment of the durability of the reservoir both in the short and long term.
Surface monitoring, where required by permit, should be completed at site-specific frequency and spatial distribution determined by the permitting regime to monitor any CO2 leakageleaks [A]. This includes monitoring of:
Near-surface monitoring is required at a site-specific frequency and spatial distribution in order to monitor any CO2 movement to above the reservoir seal and potential impact to USDWs [A]. This includes monitoring of:
Subsurface monitoring is required to monitor the temperature and pressure within the reservoir as well as detect and monitor the lateral extent and boundaries of injected CO2 migration within the storage reservoir to ensure that the plume stays within the target reservoir. Additionally, it can inform on the behavior and secondary trapping of CO2 within the reservoir. Plume and pressure-front monitoring results also provide necessary data for comparison to and verification of model predictions, if major deviations from the model are observed, operations should be modified to try and increase secondary trapping (e.g., residual/solubility/mineralization) and/or update monitoring plan. The owner/operator will use a site-specific and complementary suite of methods to trace the carbon dioxide plume and area of elevated pressure. Available methods for plume and pressure-front tracking include: (1) fluid pressure and temperature monitoring (direct); (2) geophysical monitoring (indirect); (3) groundwater geochemical monitoring (direct); and (4) computational modeling (indirect). Monitoring should include both direct and indirect monitoring [A,B,C].
Where indirect monitoring is not appropriate or there may be risks associated with the dissolved-phase plume [A], the regulators or certified geologist may determine the use of geochemical monitoring necessary to track the CO2 plume extent. Formation fluid pH and conductivity must be measured prior to injection. Geochemical analysis can also help determine the behavior of CO2 in the subsurface. For example, pH can impact CO2 solubility (how much CO2 will dissolve) as well as water-rock interactions (how much CO2 will mineralize). Gas composition is important to identify if any modification occurred in the subsurface. TheseFormation fluid measurements could include but are not limited to:
Reservoir modeling must be performed, including pressure and fracture simulations. This could be either using traditional reservoir models or CCSNET AI models1611. The model should be compared to data directly collected from the reservoir (e.g., pressure, temperature) and any other nearby relevant subsurface data (i.e., porosity and permeability of our injection horizon and confining layer, injection history, rock mechanical properties, mapped faults, etc) to ensure model validity and confirm the containment of CO2 within targeted injection zone. Reservoir models must be updated as operational data changes [A,B,C].
Surface monitoring, where required by permit, should be completed at a site-specific frequency and spatial distribution determined by the permitting regime to monitor anyfor CO2 leakageleaks. This should include measurement of CO2 density and flux to identify large point-source leaks for example by [A]:
The final list of constituents to be monitored will be determined between the Project Proponent and regulating body or certified geologist on a Project-specific basis using site-specific data from site characterization and injectate composition.
When the continuous gas detection system (Section 3.1.1.1) detects gases, Projecta Triggered Gas Investigation must providecommence. anThis emergencyinvestigation responsecomprises plangas outlinescomposition correctiveanalysis actionsand whichisotope willanalysis to determine the source and extent of detected gases. Both analyses are initiated concurrently, isotope analysis is not contingent on results from composition analysis [C].
Monitoring of the wellhead pressure and composition of any gas recovered from well(s) or representative sampling locations where gas from the reservoir is detected must be completed on a monthly basis. Gas monitoring must include CO₂, CH₄, C3H8 and VOCs emissions from the well via species-specific gas monitors with a resolution of at least 0.01 vol%, or lab analysis, if sampled (e.g., gas chromatography on grab bag or equivalent samples). When concentrations above background atmospheric levels are detected, a sample must be taken into caseestablish the chemical composition of CO2the leakagedisplaced gases (including CO2, CH4, C3H8, N2, O2 and VOCs). Results must be compared to baseline values obtained prior to CO2 injection. Wellhead pressure should be monitored continuously, and wellhead gas sampling should be monthly [B,C].
The Project Proponent/Operator must prepare an emergency response plan which outlines corrective actions which will be taken in case of CO2 leakageleaks. The plan must be submitted and approved by the componentcompetent permitting authority. If any CO2 leakageleak is detected from the target reservoir or there are significant irregularities from the used model(s), the Project Proponent/OperatorsOperator must undertake corrective measures as set out in their emergency response plan and approved by the competent authority. For a loss of conformance with models, the Project Proponent must halt injection whilst they identify the cause of this loss, and then revise the monitoring plan to account for this change of migration. If there is a leak the Project Proponent must halt injection whilst they conduct an assessment to determine if the loss of containment can be repaired prior to injection beginning again. The amount of CO2 lost must also be quantified and subtracted from the overall total of CO2 storedstorage.
Re-evaluations of the CO2 plume extent must also be implemented when warranted based on observational or quantitative changes of the monitoring parameters of the storage reservoir, including but not limited to:
Further information on the risk and attribution of reversalsSection 34.30 and Section 3.34.1.
The aim of this post-injection monitoring and the closure requirements in Section 38.70 is to put in place scientific and/or operational monitoring practices that prove beyond reasonable doubt that CO2 storage will be durable on geologic timescales. Addressing potential risks to durability (Section 1.0) is important for ensuring robust and diligent CO2removals.
The Project Proponent must follow any post-injection and site decommissioning requirements of the permit for the specified Project. Post-injection is defined as monitoring between the end of injection and plugging of the wells. Once injection has ceased (e.g., this is defined as closure in the EU) the site must undergo post-injection monitoring. Once it is demonstrated that the injected plume is stable (i.e., the plume is no longer migrating) within the storage reservoir and unable to impact the USDWs, wells can be plugged, the site decommissioned (e.g., this is defined as the closure point in the US). Within the EU, the Project Proponent must transfer the site to the national/local authorities where monitoring will continue. Within the USA, additional monitoring post-closure may be discontinued if allowed under the applicable UIC permit. If operating in another region, the Project Proponent must follow guidance from the regulating authority.
[/R-TGQS-Post-injection monitoring should apply the same monitoring strategy as implemented during injection and operation, with a focus on methods tailored to address the anticipated system changes and risks that may occur. Post-injection monitoring must be carried out in accordance with the local permitting regime (for approved permits) or the certified monitoring plan (for other jurisdictions). This monitoring must include reservoir modeling alongside indirect seismic imaging and direct measurements from the injection well of formation fluid temperature and reservoir pressure and pressure in the zone immediately above the sealing interval to trace plume migration and the pressure front. Seismic monitoring using regional seismic data must continue, and events of magnitude 2.7 or greater must be reported. Corrosion monitoring and external mechanical integrity testing must be conducted annually for the first three years after injection. Annulus pressure must initially be measured monthly. A pressure fall-off test must initially be conducted every two years. It is recommended that USDWs be monitored to identify and address any leakageCO2 leak pathways that arise. Any measured parameters should be compared to modeled predictions to help refine the model or identify possible risks. The frequency of post-injection monitoring may be reduced, determined by specific, risk-based, quantitative criteria detailed as part of the regulating permit or approved montiroing plan. Such criteria could include the reservoir pressure reaching a certain level relative to pre-injection conditions or steady or favorable trends in observed geochemical monitoring results over a predefined period, and agreement with model predictions.
After a minimum of 15 years (USA) or 20 years (EU) or equivalent, an assessment must be completed to demonstrate plume stabilization or a trend towards stabilization. Reassessments must be carried out until permanent containment of the stored CO2 is demonstrated in order to eliminate the risk of migration or release of CO2 from the storage formation to the atmosphere or USDWs [addresses risk A]. The Project Proponent will actively explore emerging technologies for measuring plume stabilization. The plume stabilization assessment shall be conducted in one of the following ways:
The time frame for post injection monitoring should be aligned with regulatory guidance and based on site specific operation and monitoring data, for example whether plume stabilization is demonstrated. If the regulating authority does not have guidance on the minimum time frame, this is set at a minimum of 50 years. The length of ongoing monitoring will be subject to change given subsequent reanalyses.
If the plume stabilization can be demonstrated by the above methods, and is independently reviewed and certified by a Certifiedregistered Professional Geologist (i.e. Chartered Geologist or equivalent), the CO2 plume will be considered stabilized and the site decommissioned following requirements in Section 38.70.
The reversal risk shall be determined on a project by project basis. There should be no reversals unless there is a loss of caprock or well integrity, and this technology does not yet have a documented history of reversals. There is, however, a risk of methane production within the reservoir, based on current literature, but this risk is very small87. Based on present levels of scientific knowledge, Projects applicable to this Module are typically categorized as having a Very Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire (also found in the relevant Protocol). This results in a 1% buffer pool for Projects using this Storage Module. This reversal risk will be reassessed everyat 5the years,renewal aligning withof the Crediting Period, or when new scientific research and knowledge are produced.
In instances where reversals are determined to be a result of negligence by the storage operator, Project Crediting may be ceased. Reversals will be accounted for by Projects and the Isometric Registry as detailed in **the Reversal and Buffer Pool Section 5.6** of the Isometric Standard.
When a reversal is detected and quantified, there are multiple considerations that will be taken into account to attribute the reversal to whatever has been injected in the targeted reservoir.
In instances where reversals are determined to be a result of negligence by the operator or Project Proponent, project crediting may be ceased.
[math: CO_2e_{StoredStorage,\ RP}] represents the amount of CO2 present in the CO2-containing injectant that is injected and stored in the geologic or engineered storage formation in a given [math: RP]. This is the gross mass stored and does not account for reversals of storage from the storage formation.
This can be calculated by using the mass injected and the average concentration of CO2 in the injectant over a given time period, summed across the whole [math: RP]:
[math: CO_2e_{StoredStorage,\ RP} = \sum_{t=1}^{T} C_{mean, inj,t} \cdot m_{inj,t}]
(Equation 1)
Where:
The mass of CO2-containing injectant, [math: m_{inj,t}], may either be directly measured using a mass flow meter, or may be indirectly measured by combining suitable volume and density measurements. In the latter case, the mass of injectant is calculated as:
[math: m_{inj,t} = V_{inj,t} \cdot \rho_{inj,t}]
(Equation 2)
Where:
The density of the injectant may be measured either using a calibrated density meter, or may be indirectly measured by combining suitable pressure and temperature measurements. In the latter case, the density should be determined as a function of the pressure and temperature measurements by application of a suitable gas-phase equation of state model. Supporting information, including appropriate published scientific literature and/or internal empirical evidence, demonstrating the accuracy of the applied equation of state must be provided at the point of third party project verification.
Calculation of [math: CO_2e_{StoredStorage,\ RP}] requires two primary measurements
The concentration of CO2 in the gaseous, dissolved or supercritical CO2 stream must be:
The mass of injectant ([math: m_{Inj}]) is measured via use of a calibrated mass flow meter or volumetric flow meter and density measurements over a defined time interval ([math: Δt]). Preference is for high-accuracy flow meters such as coriolis or thermal mass flow meters, although other metering solutions are allowable. Flow metering must meet the following requirements:
In general, the Project Proponent must identify, highlight, and explain any data gaps or missing calibration data, if any occur. The Project Proponent must notify Isometric and the VVB when data gaps or missing calibration data occur and must clearly explain the approach taken and document the missing data within the GHG Statement.
For those parameters where frequent, sub-hourly measurements are required (notably CO2 concentration measurements in the CO2 stream, and the measurement of mass of CO2 injected), the Project Proponent must adhere to the following procedure for handling missing data.
Where there are data gaps in measurement of the relevant parameter of up to 30 minutes, the Project Proponent may claim using an average quantity, based on the measurements proceeding and following the data gap.
Where there are such data gaps of longer than 30 minutes, the Project Proponent may apply this approach for up to a 30 minute period within the duration of the data gap, but no more than this. For the remainder of the period of the data gap, i.e. in excess of 30 minutes, no carbon dioxide removal may be claimed, due to a lack of data. In addition, data gaps must account for less than 5% of the data used for the removal calculation within a given Reporting Period, any missing data above this is also not creditable.
Where a calibration is missed, one must be completed as soon as this is noticed. For data collected between when the calibration was required and when it actually took place, a conservative estimate should be used, as agreed between the VVB, Project Proponent, and Isometric.
The Project Proponent must maintain the following records as evidence of gross CO2 storedstorage in injected CO2 or CO2-containing injectant:
Records of all analyses and injections must be maintained by the injection facility or Project Proponent and provided for verification purposes for a minimum of five years.
Type: Counterfactual
The counterfactual for eligible projects is considered to be zero.
Type: Emissions
[math: CO_{2}e_{Emissions}] is the total greenhouse gas emissions associated with a given Reporting Period, [math: RP], or batch, [math: n].
Equations and emissions calculation requirements for [math: CO_{2}e_{Emissions}], including considerations for monitoring activities, are set out in the relevant Protocol and are not repeated in this Module.
In order to decommission a site, the Project Proponent must prove beyond reasonable doubt that injected CO2 will cause no harm to USDWs and stay within the target reservoir, thus demonstrating CO2 storage will be durable for the expected >100,000-year timescales. The Project Proponent shall ensure that all the regulators permit requirements associated with planning for, preceding with and monitoring of well or site decommissioning are adhered to and documented.
[/R-During decommissioning, the Project Proponent shall ensure flushing of all wells with a buffer fluid, determine bottom hole reservoir pressure, and perform a final external mechanical integrity test to ensure that plugging materials and procedures are selected correctly. All injection and monitoring wells should then be plugged appropriately, for example multiple plugs of CO2 resistant cement, and to the regulators requirements.
A site report (providing information on the operation, monitoring & modeling and closure procedures) should be created by the Project Proponent and submitted to regulatory bodies and carbon dioxide storage agreements with pore space owners will ensure activity in the storage site is prohibited for perpetuity following CO2 injection, ensuring that even if CO2 does not dissolve or precipitate, it will not be subject to pressure disturbances (i.e, injection or production activities) in the storage reservoir and land owners will be aware. It is also recommended that the Project Proponent notifies other stakeholders, such as nearby drinking water utilities and agencies with primacy for drinking water regulations. A copy of the site decommissioning plan should also be retained by the Project Proponent for a minimum of 10 years (or longer if required by the regulator) following site decommissioning.
Within the US, site decommissioning does not eliminate any potential responsibility or liability of the owner or operator under other provisions of law. For example, the Project Proponent may still hold some responsibility for any remedial action deemed necessary for USDW endangerment caused by the injection operation. Within the EU, the site is transferred from the Project Proponent to a competent authority (i.e., national or local authorities) once plume stability has been established and the site decommissioned. After the transfer of responsibility, the competent authority will continue with monitoring at a reduced rate which still allows for identification of CO2 leakagesleaks or significant irregularities. The monitoring rateThis will be increasedintensified if CO2 leakagesleaks or significant irregularities are identified. If operating in other jurisdiction, the relevant regulations regarding liability must be followed and disclosed within the PDD.
All records associated with the characterization, design, construction, injection operation, monitoring, and site closure shallmust be developed, submittedreported in the project design document, to the VVB and to proper authorities as required by the regulating permit.
AllRecords recordsof shalllaboratory analyses and relevant permit limitations to demonstrate compliance must be maintained in accordance with the well permit and available for review at any point during the Crediting Period or post closure. Where not required by the permit, records of all analyses and injections must be maintained by the storage facility or Project Proponent and provided for verification purposes for a minimum of 10five years after the wellend closureof the monitoring period.
All closure and post-closure monitoring records shallmust be maintained by the Project Proponent for a minimum of 10 years after closure. These records must be made available to be consulted by interested parties for reviewfuture upon request orclarifications if concerns are raisedneeded.
Isometric would like to thank Chris Holdsworth (University of Edinburgh) for contributing to this Module.
Rebecca Tyne, Ph.D.
Nicholas Ashmore, Ph.D.
This appendix details how the Project Proponent must monitor, document and report all metrics identified within this Module to demonstrate the durability of carbon dioxide removal. Following this guidance will ensure the Project Proponent measures and confirms carbon dioxide removed and long-term storage compliance, and will enable quantification of the emissions removal resulting from the Project activity during the Project Crediting Period, prior to each verification.
This methodology utilizes a comprehensive monitoring and documentation framework that captures the GHG impact in each stage of a Project. Monitoring and detailed accounting practices must be conducted throughout to ensure the continuous integrity of the carbon dioxide removals and credits.
The Project Proponent must develop and apply a monitoring plan according to ISO14064-2 principles of transparency and accuracy that allows the quantification and proof of GHG emissions removals.
Table A.1A1 Pre-Injection Monitoring Requirements
Requirement | Measurement Description | Measurement Method | Base Frequency | Required by the Protocol | Requirement Conditions | Required Evidence | Evidence Reporting | Section Reference |
|---|---|---|---|---|---|---|---|---|
Porosity & Permeability | Porosity & permeability of sequestration zone strata, caprock and any confining layers | Laboratory tests, literature | Once | Required | Porosity and permeability values | Approved Permit, literature or testing data | ||
Subsurface structures and features | Baseline assessment of subsurface structure including any faults or artificial penetrations (e.g., abandoned wells) | Seismic, electrical resistivity tomography, ground penetrating radar, step rate test | Once | Required | Testing data - survey results, Fracture assessment could be step rate test results | Approved Permit, literature or testing data | ||
Reservoir volume | Volume of sequestration zone | Once | Required | Predicted total volume | Approved Permit, literature or testing data | |||
Injectivity | Capacity of the reservoir to receive injected fluid | Once | Required | Testing data | Approved Permit, literature or testing data | |||
Fluid saturation | Fraction of pore space of a rock that is occupied by fluid | Core sampling, wireline log | Once | Required | Testing data - saturation values | Approved Permit or testing data | ||
Reservoir pressure | Pressure of fluids in the reservoir | Bottomhole pressure sensor or calculated from wellhead pressure sensors | Once | Required | Testing data - pressure logs |
| ||
CO2 stability and reactivity | Stability and reactivity of CO2 in the target formation | Core analysis | Once | Required | Testing data - brine/CO2 interactions, calculation from other parameters | Approved Permit or testing data | ||
Emergency Response Plan | Written emergency response plan and procedure in case of significant loss of containment is detected including operational procedures and procedures to ensure public safety. | Required | Emergency response plan |
| ||||
Formation fluid temperature | Temperature probe, calculation | Once | Required | Testing data, calculation - temperature log | Approved Permit or testing data | |||
Formation fluid pH | pH meter | Once | Required | Testing data - pH | Approved Permit or testing data | |||
Formation fluid conductivity/salinity | e.g., conductivity probe or other method | Once | Required | Testing data - conductivity, salinity or chloride content data | Approved Permit or testing data | |||
Formation fluid density | Standard methodology | Once | Required under certain circumstances |
| Testing data - fluid density | Approved Permit or testing data | ||
Formation fluid dissolved gas concentrations | Gas chromatography | Once | Required under certain circumstances | If required by permit | Testing data - dissolved gas concentrations | Approved Permit or testing data | ||
Composition of residual hydrocarbons | e.g., Gas chromatography | Once | Required | Legacy or testing data of the concentration of major hydrocarbon components | Approved Permit or testing data | |||
Maximum allowable surface injection pressure | Maximum pressure at injection wellhead to prevent fracturing of confining layer | In coordination with regulator | Once | Required | Permit | Permit |
| |
Surface elevation & displacement | e.g., SAR/inSAR, surface or subsurface tiltmeters, GPS instruments | Once | Required under certain circumstances | If required by permit | Baseline surface elevation data | Approved Permit or testing data | ||
Surface CO2 fluxes | Onshore operation CO2 flux monitoring | Use one of the following methods: Eddy Covariance, Optical sensors, portable/stationary CO2 detectors, chemical tracers. | Sufficient time period to capture natural variability | Required under certain circumstances | If required by permit | Baseline CO2/chemical tracers flux or pH | Approved Permit or testing data | |
Offshore operation CO2 flux monitoring | Use one of the following methods: pH or chemical tracers. | Sufficient time period to capture natural variability | Required under certain circumstances | If required by permit | Baseline CO2/chemical tracers flux or pH | Approved Permit or testing data | ||
Ecosystem imaging | Site-based phenocam, medium or high resolution remote sensing, visual inspection | Once | Required under certain circumstances | If required by permit | Background ecosystem survey | Approved Permit or testing data | ||
| Pressure above the target reservoir interval | Injection well pressure sensors, monitoring wells | Once | Required | Testing data - pressure logs | Approved Permit or testing data | ||
Reservoir modeling | Modeling of plume migration in the reservoir | Computational modeling | Once | Required | Simulation outputs - CO2 plume migration over project lifetime, associated pressure front, pressure dissipation, uncertainty analysis |
| ||
USDW temperature | Temperature probe, calculation | Once | Required under certain circumstances | If required by permit | Testing data - temperature | Approved Permit or testing data | ||
USDW salinity/conductivity | e.g., conductivity probe or other method | Once | Required under certain circumstances | If required by permit | Testing data - conductivity, salinity or chloride content data | Approved Permit or testing data | ||
USDW dissolved gas concentration | Gas chromatography | Once | Required under certain circumstances | If required by permit | Testing data - gas concentrations | Approved Permit or testing data | ||
USDW pH | pH meter | Once | Required under certain circumstances | If required by permit | Testing data - pH | Approved Permit or testing data | ||
USDW density | Standard methodology | Once | Required under certain circumstances | If required by permit | Testing Data - density | Approved Permit or testing data | ||
USDW TDS | TDS meter | Once | Required under certain circumstances | If required by permit | Testing data - TDS | Approved Permit or testing data |
Table A.2A2 Operational Monitoring Requirements
Requirement | Measurement Description | Measurement Method | Base Frequency | Required by the Protocol | Requirement Conditions | Required Evidence | Evidence Reporting | Section Reference |
|---|---|---|---|---|---|---|---|---|
Injection pressure | Surface injection pressure (must remain below the maximum allowable surface pressure) | Wellhead pressure sensors | Continuous | Required | Testing data - pressure log | Approved Permit or testing data | ||
Injection rate and volume | The rate and amount of material that is injected | Flow meter | Continuous | Required | Testing data - flow data | Testing data | ||
Injectate stream pH | pH meter | Daily, or less frequently if statistically similar | Required under certain circumstances | If dissolved CO2 | Testing data - pH | Approved Permit or testing data | ||
Injectate stream temperature | Temperature sensor | Daily | Required | Testing data - temperature log | Approved Permit or testing data | |||
Injectate stream impurities | Impurity concentrations in the injectate stream (e.g., arsenic, sulfides, mercury) | Impurity-dependent; must be agreed with regulator | As per permit | Required under certain circumstances | If required by permit | Concentrations of targeted impurities | Approved Permit or testing data | |
Injectate stream CO2 concentration | CO2 sensor | Continuous | Required | Testing data - CO2 concentration logs | Testing data | |||
Injectate stream viscosity | Viscometer | As per permit | Required under certain circumstances | If required by permit | Testing data - viscosity | Approved Permit or testing data | ||
Annulus pressure | Pressure within the wellbore annulus | Annulus pressure sensor | Continuous | Required | Testing data - pressure log | Approved Permit or testing data | ||
Corrosion monitoring | Monitoring of well casing for corrosion | Corrosion coupons, flow loops, multi-finger calipers | Quarterly | Required | Testing data - evidence of no corrosion | Approved Permit or testing data | ||
External mechanical integrity tests | Monitoring of external integrity (cement) to prevent | e.g., oxygen activation log, temperature log/sensor, noise log | Annually | Required | Testing data - no evidence of loss of well conformity | Approved Permit or testing data | ||
Pressure fall-off test | Periodic test to measure changes in the near-wellbore environment | Fall-off test | Every two years | Required | Testing data - disclosure of any changes | Approved Permit or testing data | ||
Reservoir pressure | Pressure of fluids in the reservoir | Bottomhole pressure sensor or calculated from wellhead pressure sensors | Continuous | Required | Testing data - pressure logs |
| ||
| Pressure | Injection well pressure sensors, monitoring wells | Continuous | Required | Testing data - pressure logs | Testing data | ||
Reservoir modeling | Modeling of plume migration in the reservoir | Computational modeling | As operational data changes | Required | Simulation outputs - CO2 plume migration over project lifetime, associated pressure front, pressure dissipation, uncertainty analysis |
| ||
Indirect plume monitoring | Indirect assessment of plume migration using geophysical techniques | Geophysical surveys - seismic, electrical resistivity, sonar | Every 5 years | Required under certain circumstances | If fluid contrast is significant enough to be visible (e.g., supercritical CO2) | Testing data - survey results | Approved Permit or testing data | |
Wellhead gas composition | Gas chromatography or equivalent | Monthly | Required under certain circumstances | If wellhead gas is present | Concentration of gaseous species present | Testing data | ||
Induced seismicity | Monitoring for seismic activity caused by operations | Monitor regional seismic data for events using existing databases | Continuous | Required | Notification of any events over magnitude 2.7 | Notification of seismic event | ||
Surface CO2 fluxes | Onshore operation CO2 flux monitoring | Use one of the following methods: Eddy Covariance, Optical sensors, portable/stationary CO2 detectors, chemical tracers. | As per permit | Required under certain circumstances | If required by permit | CO2/chemical tracers flux or pH | Approved Permit or testing data | |
Offshore operation CO2 flux monitoring | Use one of the following methods: pH or chemical tracers. | As per permit | Required under certain circumstances | If required by permit | CO2/chemical tracers flux or pH | Approved Permit or testing data | ||
Ecosystem imaging | Site-based phenocam, medium or high resolution remote sensing, visual inspection | As per permit | Required under certain circumstances | If required by permit | Ecosystem survey results | Approved Permit or testing data | ||
Surface elevation & displacement | e.g., SAR/inSAR, surface or subsurface tiltmeters, GPS instruments | As per permit | Required under certain circumstances | If required by permit | Surface elevation data | Approved Permit or testing data | ||
Formation fluid pH | pH meter | As per permit | Required under certain circumstances | If required by permit | Testing data - pH | Approved Permit or testing data | ||
Formation fluid conductivity/salinity | e.g., conductivity probe or other method | As per permit | Required under certain circumstances | If required by permit | Testing data - conductivity, salinity or chloride content data | Approved Permit or testing data | ||
Formation fluid temperature | Temperature of reservoir formation fluid to determine CO2 phase behaviour and state | Temperature probe, calculation | Continuous unless otherwise stated in permit | Required | Testing data - temperature log | Approved Permit or testing data | ||
Formation fluid density | Standard methodology | As per permit | Required under certain circumstances | If required by permit | Testing data - fluid density | Approved Permit or testing data | ||
Formation fluid dissolved gas concentrations | Gas chromatography | As per permit | Required under certain circumstances | If required by permit | Testing data - dissolved gas concentrations | Approved Permit or testing data | ||
USDW temperature | Temperature probe, calculation | As per permit | Required under certain circumstances | If required by permit | Testing data - temperature | Approved Permit or testing data | ||
USDW salinity/conductivity | e.g., conductivity probe or other method | As per permit | Required under certain circumstances | If required by permit | Testing data - conductivity, salinity or chloride content data | Approved Permit or testing data | ||
USDW dissolved gas concentration | Gas chromatography | As per permit | Required under certain circumstances | If required by permit | Testing data - gas concentrations | Approved Permit or testing data | ||
USDW pH | pH meter | As per permit | Required under certain circumstances | If required by permit | Testing data - pH | Approved Permit or testing data | ||
USDW density | Standard methodology | As per permit | Required under certain circumstances | If required by permit | Testing data - density | Approved Permit or testing data | ||
USDW TDS | TDS meter | As per permit | Required under certain circumstances | If required by permit | Testing data - TDS | Approved Permit or testing data |
Table A.3A3 Post-Injection Monitoring Requirements
Requirement | Measurement Description | Measurement Method | Base Frequency | Required by the Protocol | Requirement Conditions | Required Evidence | Evidence Reporting | Section Reference |
|---|---|---|---|---|---|---|---|---|
Annulus pressure | Pressure within the wellbore annulus | Annulus pressure sensor | Initially monthly but can be reduced over time | Required | Testing data - pressure log | Approved Permit or testing data | ||
Corrosion monitoring | Monitoring of well casing for corrosion | Corrosion coupons, flow loops, multi finger calipers | Initially annually but can be reduced after a minimum of 3 years | Required | Testing data - evidence of no corrosion | Approved Permit or testing data | ||
External mechanical integrity tests | Monitoring of external integrity (cement) to prevent | e.g., oxygen activation log, temperature log/sensor or noise log | Initially annually but can be reduced after a minimum of 3 years | Required | Testing data - no evidence of loss of well conformity | Approved Permit or testing data | ||
Pressure fall | Periodic test to measure for changes in the near wellbore environment | Fall-off test | Initially every 2 years but can be reduced over time | Required | Testing data - disclosure of any changes | Approved Permit or testing data | ||
Reservoir pressure | Pressure of fluids in the reservoir | Bottomhole pressure sensor or calculated from wellhead pressure sensors | Continuous | Required | Testing data - pressure logs |
| ||
| Pressure | Injection well pressure sensors, monitoring wells | Continuous | Required | Testing data - pressure logs | Testing data | ||
Reservoir modeling | Modeling of plume migration in the reservoir | Computational modeling | As monitoring data changes | Required | Simulation outputs - CO2 plume migration over project lifetime, associated pressure front, pressure dissipation, uncertainty analysis |
| ||
Indirect Plume monitoring | Indirect assessment of plume migration using geophysical techniques | Geophysical surveys - seismic, electrical resistivity | Every 5 years | Required under certain circumstances | If fluid contrast is significant enough to be visible (e.g., supercritical CO2) | Testing data - survey results | Approved Permit or testing data | |
Wellhead gas composition | Gas chromatography or equivalent | Monthly | Required under certain circumstances | If wellhead gas is present | Concentration of gaseous species present | Testing data | ||
Induced seismicity | Monitoring for seismic activity caused by operations | Monitor regional seismic data for events using existing databases | Continuous | Required | Notification of any events over magnitude 2.7 | Notification of seismic event | ||
Surface CO2 fluxes | Onshore operation CO2 flux monitoring | Use one of the following methods: Eddy Covariance, Optical sensors, portable/stationary CO2 detectors, chemical tracers. | As per permit | Required under certain circumstances | If required by permit | CO2/chemical tracers flux or pH | Approved Permit or testing data | |
Offshore operation CO2 flux monitoring | Use one of the following methods: pH or chemical tracers. | As per permit | Required under certain circumstances | If required by permit | CO2/chemical tracers flux or pH | Approved Permit or testing data | ||
Ecosystem imaging | Site-based phenocam, medium or high resolution remote sensing, visual inspection | As per permit | Required under certain circumstances | If required by permit | Ecosystem survey results | Approved Permit or testing data | ||
Surface elevation & displacement | e.g., SAR/inSAR, surface or subsurface tiltmeters, GPS instruments | As per permit | Required under certain circumstances | If required by permit | Surface elevation data | Approved Permit or testing data | ||
Formation fluid pH | pH meter | As per permit | Required under certain circumstances | If required by permit | Testing data - pH | Approved Permit or testing data | ||
Formation fluid conductivity/salinity | e.g., conductivity probe or other method | As per permit | Required under certain circumstances | If required by permit | Testing data - conductivity, salinity or chloride content data | Approved Permit or testing data | ||
Formation fluid temperature | Temperature of reservoir formation fluid to determine CO2 phase behaviour and state. | Temperature probe, calculation | Continuous unless otherwise stated in the per permit | Required | Testing data - temperature log | Approved Permit or testing data | ||
Formation fluid density | Standard methodology | As per permit | Required under certain circumstances | If required by permit | Testing data - fluid density | Approved Permit or testing data | ||
Formation fluid dissolved gas concentrations | Gas chromatography | As per permit | Required under certain circumstances | If required by permit | Testing data - dissolved gas concentrations | Approved Permit or testing data | ||
USDW temperature | Temperature probe, calculation | As per permit | Required under certain circumstances | If required by permit | Testing data - temperature | Approved Permit or testing data | ||
USDW salinity/conductivity | e.g., conductivity probe or other method | As per permit | Required under certain circumstances | If required by permit | Testing data - conductivity, salinity or chloride content data | Approved Permit or testing data | ||
USDW dissolved gas concentration | Gas chromatography | As per permit | Required under certain circumstances | If required by permit | Testing data - gas concentrations | Approved Permit or testing data | ||
USDW pH | pH meter | As per permit | Required under certain circumstances | If required by permit | Testing data - pH | Approved Permit or testing data | ||
USDW density | Standard methodology | As per permit | Required under certain circumstances | If required by permit | Testing Data - density | Approved Permit or testing data | ||
USDW TDS | TDS meter | As per permit | Required under certain circumstances | If required by permit | Testing data - TDS | Approved Permit or testing data |
Here is a list of permitsPermits which are currently approved by Isometric are listed below. These permits are in regime with strong track records of safe CO2 injection and publicly available robust regulations. As new regulatory regimes are developed, this list will be updated.
Current approved regulatoring permits:
Ghanbari, S., Mackay E.J., Heinemannn N., Alcalde J., James, A., Allen, M.J. (2020). Impact of CO2 mixing with trapped hydrocarbons on CO2 storage capacity and security: A case study from the Captain aquifer (North Sea). Applied Energy, 278, 115634. https://doi.org/10.1016/j.apenergy.2020.115634↩
Kaldi, J., Daniel, R., Tenthorey, E., Michael, K., Schacht, U., Nicol, A., Underschultz, J. and Backe, G. (2013). Containment of CO2 in CCS: Role of caprocks and faults. Energy Procedia, 37, 5403–5410. https://doi.org/10.1016/j.egypro.2013.06.458↩↩2
Jha, B. and Juanes, R. (2014). Coupled multiphase flow and poromechanics: A computational model of pore pressure effects on fault slip and earthquake triggering. Water Resources Research, 50, 3776–3909. https://doi.org/10.1002/2013WR015175↩
Rinaldi, A. P., Rutqvist, J. and Cappa, F. (2014). Geomechanical effects on CO2 leakage through fault zones during large-scale underground injection. International Journal of Greenhouse Gas Control, 20, 117–131. https://doi.org/10.1016/j.ijggc.2013.11.001↩
Vilarrasa, V., Makhnenko, R. Y. and Lyesse Laloui. (2017). Potential for fault reactivation due to CO2 injection in a semi-closed saline aquifer. Energy Procedia, 114, 3282–3290. https://doi.org/10.1016/j.egypro.2017.03.1460↩
Zoback, M. D. and Gorelick, S. M. (2012). Earthquake triggering and large-scale geologic storage of carbon dioxide. Proceedings of the National Academy of Sciences, 109, 10164–10168. https://doi.org/10.1073/pnas.1202473109↩↩2
Vilarrasa, V. and Carrera, J. (2015). Geologic carbon storage is unlikely to trigger large earthquakes and reactivate faults through which CO2 could leak. Proceedings of the National Academy of Sciences, 112, 5938–5943. https://doi.org/10.1073/pnas.1413284112↩
Tyne, R. L., Barry, P. H., Lawson, M., lloyd, K. G., Giovannelli, D., Summers, Z. M., and Ballentine, C. J. (2023). Identifying and Understanding Microbial Methanogenesis in CO2 Storage. Environmental Science & Technology, 57, 9459–9473. https://doi.org/10.1021/acs.est.2c08652↩↩2
Jones, D. M., I. M. Head, N. D. Gray, J. J. Adams, A. K. Rowan, C. M. Aitken, B. Bennett, H. Huang, A. Brown, B. F. J. Bowler, T. Oldenburg, M. Erdmann and S. R. Larter (2008). Crude-oil biodegradation via methanogenesis in subsurface petroleum reservoirs. Nature, 451(7175): 176-180. ↩
Gieg, L. M., T. R. Jack and J. M. Foght (2011). Biological souring and mitigation in oil reservoirs. Appl Microbiol Biotechnol, 92(2): 263-282. ↩
Skovhus, T. L., R. B. Eckert and E. Rodrigues (2017). Management and control of microbiologically influenced corrosion (MIC) in the oil and gas industry-Overview and a North Sea case study. J Biotechnol, 256: 31-45. ↩
Scheffer, G., C. R. J. Hubert, D. R. Enning, S. Lahme, J. Mand and J. R. de Rezende (2021). Metagenomic Investigation of a Low Diversity, High Salinity Offshore Oil Reservoir. Microorganisms, 9(11). ↩
Chen, Y., Guerschman, J. P., Cheng, Z., and Guo, L. (2019). Remote sensing for vegetation monitoring in carbon capture storage regions: A review. Applied Energy, 240, 312–326. https://doi.org/10.1016/j.apenergy.2019.02.027↩
Flohr, A., Matter, J. M., James, R. H., Saw, K., Brown, R., Gros, J., Flude, S., Day, C., Peel, K., Connelly, D., Pearce, C. R., Strong, J. A., Lichtschlag, A., Hillegonds, D. J., Ballentine, C. J., and Tyne, R. L. (2021). Utility of natural and artificial geochemical tracers for leakage monitoring and quantification during an offshore controlled CO2 release experiment. International Journal of Greenhouse Gas Control, 111, 103421. https://doi.org/10.1016/j.ijggc.2021.103421↩↩2
Weber, U. W., Kampman, N., and Sundal, A. (2021). Techno-economic aspects of noble gases as monitoring tracers. Energies, 14, 3433. https://doi.org/10.3390/en14123433↩
Wen, G. and Benson, S. M. CCSNet, a deep learning modeling suite for CO2 storage. https://ccsnet.ai/↩↩2
Flohr, A., Schaap, A., Achterberg, E. P., Alendal, G., Arundell, M., Berndt, C., Blackford, J., Böttner, C., Borisov, S. M., Brown, R., Bull, J. M., Carter, L., Chen, B., Dale, A. W., de Beer, D., Dean, M., Deusner, C., Dewar, M., Durden, J. M., Elsen, S., Esposito, M., Faggetter, M., Fischer, J. P., Gana, A., Gros, J., Haeckel, M., Hanz, R., Holtappels, M., Hosking, B., Huvenne, V. A. I., James, R. H., Koopmans, D., Kossel, E., Leighton, T. G., Li, J., Lichtschlag, A., Linke, P., Loucaides, S., Martínez-Cabanas, M., Matter, J. M., Mesher, T., Monk, S., Mowlem, M., Oleynik, A., Papadimitriou, S., Paxton, D., Pearce, C. R., Peel, K., Roche, B., Ruhl, H. A., Saleem, U., Sands, C., Saw, K., Schmidt, M., Sommer, S., Strong, J. A., Triest, J., Ungerböck, B., Walk, J., White, P., Widdicombe, S., Wilson, R. E., Wright, H., Wyatt, J., and Connelly, D. (2021). Towards improved monitoring of offshore carbon storage: A real-world field experiment detecting a controlled sub-seafloor CO2 release. International Journal of Greenhouse Gas Control, 106, 103237. https://doi.org/10.1016/j.ijggc.2020.103237↩
Cal. Code Regs., tit. 14, § 1724.14 (2017). Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations. Not accessible in the EU, copy available on request. https://www.conservation.ca.gov/index/Documents/04-26-17%20UIC%20Pre-Rulemaking%20DD%20V.2%20%28tracking%20changes%20from%20DD%20V.1%29%204-25-17.pdf↩
United States EPA. (2013). Geological Sequestration of Carbon Dioxide: Underground Injection Control (UIC) Program Class VI Well Testing and Monitoring Guidance. https://www.epa.gov/sites/default/files/2015-07/documents/epa816r13001.pdf↩
EUR-Lex (Access to European Union Law). (2009). Directive 2009/31/EC of the European Parliament and of the Council of 23 April 2009 on the geological storage of carbon dioxide and amending Council Directive 85/337/EEC, European Parliament and Council Directives 2000/60/EC, 2001/80/EC, 2004/35/EC, 2006/12/EC, 2008/1/EC and Regulation (EC) No 1013/2006. https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:32009L0031↩
Norwegian Offshore Directorate. (2017). Regulations relating to exploitation of subsea reservoirs on the continental shelf for storage of CO₂ and relating to transportation of CO₂ on the continental shelf. https://www.sodir.no/en/regulations/regulations/exploitation-of-subsea-reservoirs-on-the-continental-shelf-for-storage-of-and-transportation-of-co/↩
UK Government. (2010). The Storage of Carbon Dioxide (Licensing etc.) Regulations 2010. https://www.legislation.gov.uk/uksi/2010/2221/contents/made↩
Alberta Energy Regulator. (2023). Directive 065: Resources Applications for Oil and Gas Reservoirs. https://static.aer.ca/prd/documents/directives/Directive065.pdf↩
Alberta Energy Regulator. (2022). Directive 087: Well Integrity Management. https://static.aer.ca/prd/documents/directives/directive-087.pdf↩