Biomass or Bio-oil Storage in Permeable Reservoirs
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This Module (Independent components of Isometric Certified Protocols which are transferable between and applicable to different Protocols.) details 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.) and monitoring requirements for bio-oil and biomass 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”.) in permeable reservoirs (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).).
This Module is applicable for bio-oil (A mixture of water, organic acids, aldehydes, ketones, sugars, phenols, and other organic compounds derived from the thermal breakdown of biomass. Thermal breakdown of biomass is achieved via thermochemical processes, such as pyrolysis, which heat biomass in low- or no-oxygen environments to high temperatures (~e.g. 350-650°C). Bio-oil is often also referred to as pyrolysis oil or bio-crude.) or biomass slurry injection into permeable reservoirs (clastic and carbonate reservoirs i.e., saline aquifers and depleted hydrocarbon fields) that have been approved by the relevant permitting authority. A confining layer with low porosity, low permeability and free of geologic or man-made features that could act as conduits for leaks is required in order to prevent the migration of any buoyant fluids (for example any biogas produced) into overlying formations and act as a barrier for fracture propagation. The storage complex is defined as the storage site which is suitable for the long-term storage of carbon-laden fluids and associated elements and surrounding geological domain which can have an effect on overall storage integrity and security. It comprises a targeted reservoir/reservoir and surrounding low permeability seals which enclose the reservoir(s).
Biomass slurry is expected to be a sludgy organic waste (e.g., manure, food waste, agricultural waste, paper sludge) mixed on-site with available water sources such as brine. The slurry contains compounds such as carbon, nitrogen, phosphorus, oxygen, hydrogen, sulfur, and trace elements found in the organic waste. The injection and storage of municipal wastewater/sewage effluent has been occurring since the 1960s [^2] and biomass injection and storage has been practiced since 2008 with research development and practice led by Advantek [^1].
Bio-oil is a dark, viscous liquid with a typical pH of between 2-3, consisting of oxygenated hydrocarbon compounds1. Bio-oil can have co-products (Products that have a significant market value and are planned for as part of production.) like biochar mixed into it prior to subsurface injection. The storage of bio-oil in permeable reservoirs for the purpose of carbon storage is relatively new and has not been well studied and documented as of November 2025. Research by Charm Industrial using bench scale experiments suggest that at a viscosity of 6000 cP, bio-oils polymerize and becomes even more viscous2. They suggest this could be reached between 2 and 15 years at reservoir temperatures between 35°C and 60°C respectively reducing the risk of migration2,3.
Note: Within this Module, the words ‘bio-oil’, ‘bio-oil with biochar’, ‘biomass slurry’ and ‘injectant’/’injectate’ are used interchangeably.
The durability of biomass and bio-oil stored in geologic formations (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.) depends on the operation and monitoring of injection activities (The steps of a Project Proponent’s Removal or Reduction process that result in carbon fluxes. The carbon flux associated with an activity is a component of the Project Proponent’s Protocol.), as well as the characteristics of the biomass or bio-oil, the geologic storage complex and the interactions between the two. To ensure sufficient durability, injectate characteristics and conditions of storage 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 as well as updated over time. Subsurface injection of bio-oil/biomass into an appropriate storage complex in line with permitting requirements and this Module, is expected to result in the removal (The term used to represent the CO₂ taken out of the atmosphere as a result of a CDR process.) of carbon from the atmosphere and storage on geological timescales.
Section 2.2 outlines requirements for evaluating biomass and bio-oil injection and storage, with a focus on site characterization, well construction and monitoring. The post-injection monitoring plan detailed in Section 3.2 acts to address and mitigate these potential risks to durability. Section 4.0 addresses accounting for any emissions (The term used to describe greenhouse gas emissions to the atmosphere as a result of Project activities.) associated with these risks.
Monitoring of the injection, operations and project (An activity or process or group of activities or processes that alter the condition of a Baseline and leads to Removals or Reductions.) site shall be completed to ensure that any injectate and any biogas formed (such as CO2, CH4, or other volatiles) remains stored within the storage site and does not migrate outside of the storage complex. The injection site shall be monitored in accordance with the permitting requirements as specified in the operating permit for the injection site issued by the relevant regulatory authority.
The subsurface monitoring approach developed and implemented by the Project Proponent (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) or Operator (when the Project Proponent is not operating the site) shall address, via the permitting process and permit compliance, or by additional efforts and documentation:
[/R-Y44J-0]Specifically, the requirements in this Module must be met to ensure durable storage of biomass and bio-oil in the storage complex.
Potential risks to expected durability of biomass and/or bio-oil are site specific and may include:
Projects must submit at least one address and/or specific geo-coordinates for the project.1 PermittingProjects may submit multiple project locations – please specify what role each location plays in the project.
The injection facility and reservoir must have a current well permit issued by the responsible authority for the location of the injection facility and salt cavern, that specifically identify biomass, bio-oil or an equivalent type of injectate, as acceptable injectates is required. In addition, The Project must comply with all applicable local environmental, ecological and social requirements as well as those set out in the relevant Protocol (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.) and the Environmental and Social Impacts Section of the Isometric Standard. If there is a possibility that the reservoir could be impacted by enhanced hydrocarbon recovery (EHR or EHR+) or other production operations, storage will not be permitted.
[/R-132T-1]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) (The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.) and followed throughout the Project.
For projects operating in locations outside of these regulatory 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 salt cavern gas or waste 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 (The document that clearly outlines how a Project will generate rigorously quantifiable Additional high-quality Removals or Reductions.). Specifically, the reviewer should sign off on: (1) site characterization report; (2) risk register and mitigation plan; (3) Monitoring/Testing/Reporting plan; (4) well-integrity plan; and (5) demonstration of rigor equivalent to the listed permits. If the signed off permit is from within an approved regulatory regime (see Appendix 2), permit compliance can 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 required evidence must be submitted.
[/G-PF9S-0]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 (A systematic and independent process for evaluating the reasonableness of the assumptions, limitations and methods that support a Project and assessing whether the Project conforms to the criteria set forth in the Isometric Standard and the Protocol by which the Project is governed. Validation must be completed by an Isometric approved third-party (VVB).) & verification (A process for evaluating and confirming the net Removals and Reductions for a Project, using data and information collected from the Project and assessing conformity with the criteria set forth in the Isometric Standard and the Protocol by which it is governed. Verification must be completed by an Isometric approved third-party (VVB).) body (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.)).
[/G-A45E-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 A) 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 (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.) within 30 days of submission to the permitting authority, or upon request.
For monitoring requirements not covered under the Approved Permit, the Project Proponent (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) remains responsible for collecting and reporting all required data directly to Isometric and the 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.) 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 (The organization that develops and/or has overall legal ownership or control of a Removal or Reduction Project.) must notify Isometric and the 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.) immediately of any changes which may impact monitoring requirements. Monitoring plans will be subject to reevaluation following such changes.
The proposed storage complex must be properly characterized to demonstrate site suitability for storage and containment of the injectate including evaluating the local and regional geology, hydrogeology and any potential pathways for leaks. This characterization should also 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 and help with modeling.
[/R-MQYF-1]The site should be well characterized in accordance with the permit application and approval requirements under the relevant regulating authority. Site characterizations must include evaluation of reservoir chemistry and conditions where required to ensure compatibility of the injectate with the storage complex. The Project Proponent must demonstrate that the geologic system:
In addition, the Project Proponent must also characterize the following to assess the risk of leaks and for comparison to future measurements:
Parameter | Purpose |
|---|---|
Reservoir lithology and mineralogy | Input into reservoir and fracture simulation models allowing for prediction on the subsurface behavior and to guide injection and induced fracturing of the storage complex, ensuring there is no leak. |
Pre-existing fracture network (including fault/fracture identification, rock lithology and mineralogy, density, and stress directions) and breakdown/fracturing pressures | To determine the maximum possible magnitude and expected distribution of the seismicity from induced fracturing of the storage interval to be estimated/modeled in time as well as in space, allowing for the maximum injection rate and duration to be calculated. |
Temperature, pH, conductivity, density and fluid saturation of storage reservoir formation fluid/brine | For density and reactivity calculations and inputs into reservoir models which will guide injection. Potential interaction of the injectate under these conditions with the storage complex may impact whether any potential products (e.g., biogas) are produced as well as injectant mobility and stability. |
Dissolved gas, including of Dissolved Inorganic Carbon -DIC, composition in formation fluids, composition of any hydrocarbons present (if injection into a depleted hydrocarbon field) and composition of any tracers being used (e.g., δ13C signature and/or major and minor ion). | To determine the source of any produced biogas and extent of secondary trapping mechanisms or reactions (e.g., dissolution, methanogenesis). |
Baseline surface CO2 fluxes, where applicable | To determine a baseline for future measurements to identify if CO2 leaks are occurring. |
Baseline geophysical surveys, where applicable | To determine a baseline for future measurements to allow for changes in the subsurface induced by the injection operation to be assessed. |
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 | To determine a baseline for future measurements to identify if CO2 leaks are occurring. |
Baseline ecosystem imaging, where applicable | To determine a baseline for future measurements to identify if CO2 leaks are occurring. |
Baseline surface elevation, where applicable | To determine a baseline for future measurements to identify if CO2 leaks are occurring. |
Maximum allowable surface injection pressure | To determine the injection pressure requirements to prevent fracturing of the formation. |
The Project Proponent must demonstrate and justify that the biomass or bio-oil and injection process result in long term stability, limited lateral migration, and limited degradation such that the injectate or any gasses formed do not migrate out of the storage complex and impact fresh drinking water or above-surface environmental conditions. Justification must include reservoir simulation work if required by the relevant regulating authority permit, which considers site and injectant characteristics; alternatively, academic studies and peer-reviewed literature representative of the site and injectant characteristics, mobility studies, or other predictive data and studies completed in conjunction with performance monitoring of the formation, such as pressure front monitoring, to ensure the injectate stays within the AOR. Specific laboratory core analysis experiments with relevant cores should be conducted to confirm suitability for bio-oil sequestration operations, including quantification of bio-oil reactivity with the core. The laboratory experiments may also include quantification of the rate at which bio-oil polymerizes (solidifies), and exploration of bio-oil flow. A relevant core could be a representative rock sample from a sister reservoir, or equivalent, or core directly sampled from the project site. Site specific parameters may also result in baseline characterization of the USDWs to be required.
Site characterizations and analytical modeling shall be reviewed every five years as part of the permit renewal application minimums, at the request of the permitting authority, 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 to actual measured conditions including size, extent, and migration of the injected material, where possible, and specific operating conditions observed during injection. Estimates revised with any acquired monitoring data should demonstrate that the planned injection volume will remain within the storage complex until the end of the post-injection monitoring period.
Project validation and verification must incorporate site visits to project facilities in accordance with the requirements of ISO 14064-3, 6.1.4.2, including, at minimum, site visits during validation and initial verification, to the capture and storage site. Verifiers (i.e., VVBs) should whenever possible observe operation of the capture and storage processes to ensure full documentation of process inputs and outputs through visual observation and validation of instrumentation, measurements, and required data quality measures.
A site visit must thereafter occur at least once every 2 years at each location.
The Project Proponent must ensure that the injection well is constructed in compliance with the relevant regulating authority's permit or equivalent and documentation and records of well construction are maintained and available for review.
[/R-FPHE-1]At a minimum, the Project Proponent must ensure that all injection, observation or monitoring, legacy offset and production wells contained within the delineated AOR and that penetrate the containment or injection zones have been evaluated. Extra caution should be used on wells which penetrate the confining layers. Wells which pose a risk to durability plugged prior to injection in order to:
Casing, cement (A chemical substance used for construction that sets, hardens, and adheres to other materials to bind them together. Ordinary Portland Cement (PC) is the most common cement used in modern concrete. Other types of cement include Ground Granulated Blast-furnace Slag (GGBS), Pulverised Fly Ash (PFA) and natural pozzolans.), tubing, packer, wellhead, valves, piping, or other materials used in the construction of the injection well and any monitoring well associated with The Project must have sufficient structural strength and be designed for the life of The Project.
[/G-Y080-0]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 biomass/bio-oil and formation fluids (e.g., corrosion-resistant well casings) and must meet or exceed standards developed for such materials by API, ASTM (A standards organization that develops and publishes voluntary consensus international standards.) International, or comparable standards. The casing and cementing program must be designed to prevent the movement of fluids out of the sequestration zone and above the storage complex. Standards used by projects must be clearly outlined within The Project’s PDD.
[/Q-M039-1]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.
[/R-Q08R-1]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 leaks, changes to the assessed risks to the environment and human health, new scientific knowledge, and improvements in best available technology. At a minimum, the Project Proponent must consider the following:
Injection and injectate monitoring is required in order to determine the amount of carbon durably removed from the atmosphere, guide injection, for comparison to durability monitoring data and for input into fracture simulation/migration models for validation. This must include:
For all injectate monitoring and analyses, sufficient samples must be analyzed to determine that the composition of the injectate is within specified parameters in the relevant regulatory authority permit, where required.
For samples taken each injection, each individual injectate batch should be analyzed and characterized to ensure composition variation from batch to batch is accounted for. Samples should be well mixed and representative.
For samples measured per feedstock type, a representative value should be used. These measurements should be repeated to find representative values every time there is a material upstream process change like a new biomass feedstock. If a blended feedstock is injected, samples should be taken for each injection batch.
In addition the effects of the injectant on the reservoir rocks for the simulations should be known and records of laboratory analyses and relevant permit limitations to demonstrate compliance must be maintained in accordance with the well permit and available for review.
Wells must have species-specific gas detectors (or equivalent sensors/imaging) capable of detecting, at minimum, CO₂, CH₄ and propane (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 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 their suitability for the site conditions in the PDD [C].
Detectors/alarms must be placed on any producing wells (e.g., brine producing wells/tanks) as an alternative to wellhead monitoring. If gas is detected at the brine location and is attributed to biogas formation, continuous detection must be established at the wellhead and monitoring at the brine location must continue. The determination that detected gas is attributable to biogas formation 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). 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 Isometric. Where a Triggered Gas Investigation (Section 3.1.3.1) 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].
System Integrity monitoring is required in order to ensure that the wells being used are not currently or likely to become a pathway for leaks. Monitoring must include:
As applicable based on specific site conditions, formation type, and permit class, monitoring is required to ensure that there is no migration of injectate and any generated gases out of the storage complex. Changes versus baseline conditions and/or modeled behavior/predictions may indicate injection 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 storage complex both in the short and long term.
Near-surface monitoring is required at a site-specific frequency and spatial distribution in order to monitor any CO2 movement out of the storage complex. This includes pressure monitoring of the overlying intervals, especially those directly overlying the caprock, for example by having different sealing intervals on the injection well [A].
As applicable based on specific site conditions, formation type, and permit class, injection the Project Proponent could also include:
Subsurface monitoring is required to monitor the temperature and pressure within the storage complex as well as detect and monitor the lateral extent and boundaries of injectate or biogas migration within the storage complex to ensure that the plume stays within the storage complex. 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 and/or the monitoring plan should be updated. A combination of direct (e.g., temperature logging, monitoring, analysis of well returns) and indirect methods (e.g., advanced pressure fall off, simulation studies) are required to confirm containment of the injectate and any byproducts from biodegradation (e.g., CO2, CH4, N2, O2 and VOCs), if any, during operations and during project decommissioning. Monitoring must include both direct (e.g., temperature & pressure logging, analysis of well returns) and indirect (e.g., reservoir imaging, simulation studies) methods[A,B,C]:
As applicable based on project- and site- specific conditions the Project Proponent should also include:
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.
When the continuous gas detection system (Section 3.1.1.1) detects gases from the cavern, or gas is recovered in the displaced brine stream (or from monitoring wells or representative sampling locations when available), a Triggered Gas Investigation must commence. This investigation comprises gas composition analysis and isotope analysis 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 composition of any gas recovered in the displaced brine (or monitoring wells or representative sampling locations when available) is required on a monthly basis if gases from the cavern are detected. Gas monitoring must include CO₂, CH₄ and VOCs emissions from the salt cavern 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 to establish the chemical composition of the displaced gases (including CO2, CH4, N2, O2 and VOCs). Results must be compared to baseline (A set of data describing pre-intervention or control conditions to be used as a reference scenario for comparison.) values obtained prior to CO2 injection. Wellhead pressure should be monitored continuously, and wellhead gas sampling should be monthly [B,C].
The Project Proponent/operators must prepare an emergency response plan which outlines corrective actions which will be taken in case of biomass/biogas leaks. The plan must be submitted and approved by the competent permitting authority.
If any leaks are detected from the storage complex or there are significant irregularities from the used model(s), the Project Proponent/operators must undertake corrective measures as set out in their monitoring plan submitted and approved by the competent authority. For a loss of conformance with models/expected behaviors, 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 CO2e (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.) lost must also be quantified and subtracted from the overall total stored.
Re-evaluations of the injectate fluid plume extent must also be implemented when warranted based on observational or quantitative changes of the monitoring parameters of the storage complex, including but not limited to:
Further information on the risk and attribution of 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 4.0.
The aim of this post-injection monitoring and the closure requirements (Section 6.0) is to put in place scientific and/or operational monitoring practices that prove beyond reasonable doubt that carbon storage will be durable on geologic timescales. Addressing potential risks to durability (Section 1.0) is important for ensuring robust and diligent carbon dioxide removals.
The Project Proponent must follow any post-injection and site decommissioning requirements of the permit for the specified project. Post-injection is defined as monitoring between the end of injection and plugging of the wells. Please note, the requirements in this section should be followed prior to closure of the injection well (see Section 6.0).
[/R-Z59B-1]Post-injection monitoring must apply the same monitoring strategy as implemented during injection and operation is used (with the exception of injection specific parameters for example injection composition and fracture propagation), with a focus on methods tailored to address the anticipated system changes and risks that may occur. Any migration of fluids in an unexpected manner observed at the surface prior to closure of the site should be sampled and measured for (i) carbon content and density (as above), and any reversals in storage accounted for as outlined in Section 4.0. This monitoring therefore must focus on:
At a time period expected between 2-15 years, sampling and/or other monitoring data from the injection well and/or monitoring wells at the time intervals specified here may demonstrate that bio-oil has polymerized (solidified)9 for example by obtaining a core from the reservoir. After the given time period, the following monitoring may be required under certain site conditions:
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 in observed geochemical monitoring results over a predefined period, and agreement with model predictions.
If the plume stabilization can be demonstrated (see Section 6.0), and is independently reviewed and certified by a registered Professional Geologist (i.e. Chartered Geologist or equivalent), the injectate will be considered stabilized and the site decommissioned following requirements in Section 6.0.
The reversal risk shall be determined on a project by project basis. There should be no reversals unless there is a loss of well integrity or migration outside of the storage complex, and this technology does not yet have a documented history of reversals. Based on present levels of scientific knowledge, ++Projects applicable to this Module are typically categorized as having a Low Risk Level of Reversal according to the Isometric Standard Risk Assessment Questionnaire (also found in the relevant Protocol). This results in a 5% 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.) for Projects using this Storage Module. This reversal risk will be reassessed at the renewal 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.)++, 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 (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 the Reversal and Buffer Pool Section 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 storage complex.
[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 close and decommission a site, the Project Proponent must prove beyond reasonable doubt that injected biomass or bio-oil will stay within the storage complex with no reversals, thus demonstrating storage will be durable for the expected >10,000-year timescales. The Project Proponent shall ensure that all relevant regulatory authority permit requirements associated with planning for, preceding with and monitoring of well or storage complex closure are adhered to and documented as required by the permit. A Site Closure Plan shall be prepared in accordance with the relevant regulatory authority permit requirements.
[/R-YA02-1]Closure can occur once an assessment is completed to demonstrate that the injectate plume has stabilized or is trending towards stabilization - eliminating the risk of migration or release of the injectate or its degradation products from the storage formation to the atmosphere. 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:
If the plume stabilization 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 injectate plume will be considered stabilized and additional monitoring post-closure may be discontinued if allowed under the relevant regulatory authority permit.
The timeframe for post injection monitoring and closure should be aligned with regulatory guidance and based on site specific operation and monitoring data, for example whether plume stabilization is demonstrated. If stabilization cannot be proven and if the regulating authority does not have guidance on the minimum timeframe, this is set at a minimum of 50 years in line with the EPA (A United States Government agency that protects human health and the environment.) guidelines for geological CO2 storage. The length of ongoing monitoring will be subject to change given subsequent reanalyses.
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 cement plugs, 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 storage agreements with pore space owners will ensure activity in the storage site is prohibited for perpetuity following injection, it will not be subject to pressure disturbances (i.e., injection or production activities) in the storage complex 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.
[/G-F5JF-0]All records associated with the characterization, design, construction, injection operation, monitoring, and site closure must be developed, reported in the project design document (The document, written by a Project Proponent, which records key characteristics of a Project and which forms the basis for Project Validation and evaluation in accordance with the relevant Certified Protocol. (Also known as “PDD”).), to the VVB's and to proper authorities as required by the permit.
Records of laboratory 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.
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 five years after the end of the monitoring period (A period during which a Project has any obligations, under the selected Protocol, to submit ongoing Monitoring data to Isometric and the VVB.).
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.
Isometric would like to thank Chris Holdsworth (University of Edinburgh) and Anhar Karimjee (Kyanite Strategies) 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 CO2 removal. Following this guidance will ensure the Project Proponent measures and confirms CO2 removed and long-term storage compliance, and will enable quantification of the emissions removal resulting from the Project activity during the Project Crediting Period, prior to each Verification.
This methodology utilizes a comprehensive monitoring and documentation framework that captures the GHG impact in each stage of a Project. Monitoring and detailed accounting practices must be conducted throughout to ensure the continuous integrity of the net CO2e 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.
Table A.1 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, fracture networks, 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 | Testing data | ||
Reactivity of biomass | Stability and reactivity of biomass in the target formation | Core analysis | Once | Required | Testing data - brine/biomass interactions; calculation from other parameters | Approved Permit or testing data | ||
Emergency Response Plan | Written emergency response plan and procedure in case significant loss of containment is detected, including operational procedures and procedures to ensure public safety | Required | Emergency response plan | 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 | Protocol dependent; required for reservoirs if required by permit | Testing data - fluid density | Approved Permit or testing data | ||
Formation fluid tracers | Tracer-dependent | Once | Required under certain circumstances | If tracers are being used | 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 under certain circumstances | If in a depleted hydrocarbon reservoir | 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 in the overlying formation | 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 biomass plume migration over project lifetime, associated pressure front, pressure dissipation, uncertainty analysis, containment of fractures, pressure in fractures | Simulation outputs | ||
Dissipation interval | Characterize additional dissipation interval below the storage complex to limit downward overpressure propagation | In coordination with regulator | As per permit | Required under certain circumstances | If required in permit | Permit | Permit | |
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.2 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, this should be 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 being injected | Flow meter | Continuous | Required | Testing data - flow data | Testing data | ||
Injectate stream pH | pH meter | One sample per injection batch | Required under certain circumstances | If a biomass slurry is injected | Testing data - pH | Approved Permit or testing data | ||
Injectate stream temperature | Temperature sensor | Daily | Required | Testing data - temperature log | Approved Permit or testing data | |||
δ13C of C compounds in the injectate stream | e.g., IRMS | As per permit | Required under certain circumstances | If required by permit | Tracer concentration/composition | Approved Permit or testing data | ||
Injectate conductivity or other salinity measurement | e.g., conductivity probe or other method | One sample per production batch | Required | Testing data - conductivity, salinity or chloride content data | Testing data | |||
Analysis of bio-oil constituents | Gas chromatography-Mass Spectrometry | Once per injection batch | Required under certain circumstances | If bio-oil is being injected | Testing data - concentrations of bio-oil constituents | Testing data | ||
Average solids concentration of injectate | e.g., Weight of total solids | One sample per production batch | Required under certain circumstances | If biomass/ bio-oil with biochar is injected | Testing data - average solids content | Testing data | ||
Total Organic Carbon (TOC) of injectate | e.g., Weight % TOC | One sample per production batch | Required | Testing data - concentration TOC | Testing data | |||
Total acid number (TAN) of bio-oil | Titration (ASTM D664-18e2, ASTM D3339-21, ASTM D974-22) | One sample per injection batch | Required under certain circumstances | If bio-oil is injected | Bio-oil characterization - total acid number data | Testing data | ||
Injectate density | Density of the biomass/bio-oil being injected | Standard methodology | One sample per injection batch | Required | Testing data-density | Testing data | ||
Oxygen content of bio-oil | ASTM D5291, NREL Laboratory Analysis Procedure for Determination of Carbon, Hydrogen, and Nitrogen in Bio-oils, or equivalent | One sample per injection batch | Required under certain circumstances | If bio-oil is being injected | Oxygen concentration in wt% | Testing data | ||
Viscosity of biomass | ASTM D445-12, ASTM D7042-21a, Rheological characterization, or equivalent | One sample per injection batch | Required | Testing data - viscosity | 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 | Annually | Required | Testing data - evidence of no corrosion | Approved Permit or testing data | ||
External mechanical integrity tests | Monitoring of external integrity (cement) to prevent leaks from the well into surrounding media | e.g., oxygen activation log, temperature log/sensor or 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 for changes in the near wellbore environment | Fall-off test | Every two years unless the reservoir is being fractured, in which case annually | 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 | Testing data | ||
Pressure overlying formation | Pressure information above sealing interval,either through monitoring well or multiple sealing levels in the injection well. pressure sensor | 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 | Simulation outputs | ||
Indirect Plume monitoring | Indirect assessment of plume migration using geophysical techniques | Geophysical surveys - seismic, electrical resistivity, sonar | Every 5 years | Required under certain circumstances | As required by permit | Testing data - survey results | Approved Permit or testing data | |
Wellhead gas composition | Species-specific gas monitors (≥0.01 vol% resolution), gas chromatography, or lab analysis if sampled | Monthly | Required under certain circumstances | If Triggered Gas Investigation is ongoing | 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 1 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 1 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 help determine characteristics of the biomass in the reservoir. | 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 | ||
δ13C of C compounds in the formation fluid | e.g., IRMS, cavity ring down mass spectrometry- must be agreed with regulator | as per permit | Required under certain circumstances | If required by permit | δ13C of C compounds | Approved Permit or testing data | ||
Formation fluid composition | e.g., major cations and anions of formation fluid, water isotope ratios (δ18O and δD) | Ion chromatography | Annually | Required | Testing data | Approved Permit or testing data | ||
Formation fluid bio-oil constituents | Analysis of formation water for bio-oil constituents | Gas chromatography-Mass Spectrometry | Annually | Required under certain circumstances | If groundwater monitoring is required by permit and if bio-oil is being injected | Testing data - concentrations of bio-oil constituents in water samples | 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 | ||
USDWs 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 | ||
USDW water table level | Depth to water table | Depth to water table - monitoring well, piezometer | Annual | Required under certain circumstances | If water is being extracted for use in storage operations | Testing data - depth to water table | Testing data |
Table A.3 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 | Annually | Required | Testing data — evidence of no corrosion | Approved Permit or testing data | ||
External mechanical integrity tests | Monitoring of external integrity (cement) to prevent leaks from the well into surrounding media | 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-off test | Periodic test to measure for changes in the near-wellbore environment | Fall-off test | Every two years unless the reservoir is being fractured (then annually) | 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 | Testing data | ||
Pressure overlying formation | Pressure information above the sealing interval (via monitoring well or multiple sealing levels in the injection well) | 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 | Simulation outputs | ||
Wellhead gas composition | Species-specific gas monitors (≥0.01 vol% resolution), gas chromatography, or lab analysis if sampled | 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: 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: 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 help determine the characteristics of the biomass in the reservoir | Temperature probe; calculation | Continuous unless otherwise stated in the 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 | ||
| e | As per permit | Required under certain circumstances | If required by permit | Tracer concentration/composition | 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 | ||
Bio-oil solidification | Obtain cores of the reservoir to confirm bio-oil solidification | Coring | As per permit | Required under certain circumstances | If required by permit | Core sample | Testing data |
Here is a list of regulatory regimes, which have strong track records of safe injection and publicly available robust regulations. If a signed off permit is from one of these regulatory regimes, compliance with the permit can be used as evidence for certain requirements (Appendix 1). As new regulatory regimes are developed, this list will be updated.
Current approved regulatory regimes:
Christensen, Earl D., Steve Deutch, Cheyenne Paeper, and Jack R. Ferrell III. 2022. Elemental Analysis of Bio-Oils by Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES). Laboratory Analytical Procedure (LAP), Issue Date: May 13, 2022. Golden, CO: National Renewable Energy Laboratory. NREL/TP-5100-82586. https://www.nrel.gov/docs/fy22osti/82586.pdf. ↩
Bio-oil Sequestration as a Viable CDR Pathway, Charm Industrial, 2023↩↩2↩3↩4↩5
Staš, M., Auersvald, M., Kejla, L., Vrtiška, D., Kroufek, J., & Kubička, D. (2020). Quantitative analysis of pyrolysis bio-oils: A review. TrAC Trends in Analytical Chemistry, 126, 115857. ↩
Pollard, A. S., Rover, M. R., & Brown, R. C. (2012). Characterization of bio-oil recovered as stage fractions with unique chemical and physical properties. Journal of Analytical and Applied Pyrolysis, 93, 129-138. ↩
Area of Review (AOR) is the region around an injection well which may be endangered by the injection activity. This endangerment could come from either the increased pressure in the storage complex, or the presence of CO2. It is described according to the criteria set forth in § 40 CFR.146.06 and at minimum will be 1 mile radius. ↩
Cal. Code Regs., tit. 14, § 1724.14, “Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations,” (2017). Not accesible in the EU, Copy available on request. ↩↩2
Even if bio-oil solidification cannot be determined from acquired monitoring data, the legal agreement established with the landowner to conduct bio-oil sequestration will ensure no offset activity (i.e., injection or production) will jeopardize sequestered bio-oil for all perpetuity ↩
https://bioresourcesbioprocessing.springeropen.com/articles/10.1186/s40643-023-00654-3↩