Biomass Storage in Permeable Reservoirs

This Module details Durability and monitoring requirements for biomass storage in permeable reservoirs. Within this module durability refers to the length of time for which carbon is removed from the Earth’s atmosphere and cannot contribute to further climate change. 

This module is applicable for bio-oil 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 free of geologic or man-made features that could act as conduits for leakage 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 1960s¹ and biomass injection and storage has been practiced since 2008 with research development and practice led by Advantek².

Bio-oil is a dark, viscous liquid with a typical pH of between 2-3, consisting of oxygenated hydrocarbon compounds³. Bio-oil can have co-products 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 August 2024. Research by Charm Industrial using bench scale experiments suggest that at a viscosity of 6000 cP, bio-oils polymerize and becomes even more viscous⁴. 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 migration^{4, 5}. 

The durability of biomass and bio-oil stored in geologic formations depends on the operation and monitoring of injection activities, 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, and monitored as well as updated over time. Subsurface injection of bio-oil/biomass into an appropriate storage complex in line with the U.S. EPA Underground Injection Control (UIC) Program or equivalent permitting requirements, is expected to result in the removal of carbon from the atmosphere and storage on geological timescales. Where an injection project is undertaken outside of the USA, equivalent national injection control and permitting regulations should be followed to ensure durability. If equivalent standards are either not available or do not meet the durability requirements of this Module, the EPA UIC program guidelines should be followed by default.

Note: Within this Module, the words ‘bio-oil’, ‘bio-oil with biochar’, ‘biomass slurry’ and ‘injectant’/’injectate’ are used interchangeably. 

Potential risks to the expected durability of biomass and/or bio-oil are as follows: 

• Induced fracturing of the confining layer in addition to the storage complex:

  • The target reservoir within the storage complex may be purposely fractured to allow for the greatest amount of biomass or bio-oil storage and prevent clogging of the pore spaces. If there is induced fracturing, there is a risk that the overlying confining layer could also become fractured. Fracturing of the confining layer is unlikely to occur as injection pressures must be kept below the fracture gradient of the confining layer⁶. Any signs of loss of integrity of the confining layer will be monitored as part of the operation and post-injection monitoring plan (see Section 4.1.3 & Section 4.2).  Any releases of injectate or biogas from the storage complex must be deducted from the total CO₂ removal (see Section 4.3).

• Biomass or bio-oil may be converted into bio-gas in the storage complex, such as CO₂, CH₄, N₂, O₂ and VOCs.

  • Biomass or bio-oil could biodegrade to form CO₂, CH₄, N₂, O₂ and VOCs. Any signs of gas formation should be modeled and monitored as part of the operational and post-injection monitoring plan (see Section 4.1.3 & Section 4.2). Any gasses formed in-situ shall be considered removed due to the presence of one or more confining layers that prevent the vertical migration of buoyant phases (such as biogas) however, if there are any releases of gasses from the storage complex must be deducted from the total CO₂ removal (see Section 4.3).

• Migration outside of the intended storage complex. 

  • The storage complex may not be sufficiently characterized and modeled, resulting in unintended migration. Therefore, site characterization, including identifying and modeling any features or processes that could lead to migration outside of the storage complex is required and underpins project monitoring and reduces the overall risk of migration. 

  • Bio-oil may not undergo polymerization post-injection, and remains as a liquid which could migrate out of the intended storage complex. Even if bio-oil does polymerise, migration (of bio-oil or any gasses formed) out of the intended storage complex is a possible risk before this occurs. Bio-oils as a category cover a wide variety of characteristics, with significant variation across bio-oils produced based on the feedstock, biomass conversion process, operating conditions, and processing undertaken^{7, 8}. Specific characteristics of bio-oils such as total acid number (TAN), pH, and oxygen content, can impact stability of bio-oil and likely its tendency to polymerize (solidify).  Biomass slurry could also migrate outside the intended storage complex. Migration and confinement must therefore be monitored and modeled (see Section 4.1.3 & Section 4.2). 

  • Migration out of the intended formation may also result from a loss of wellbore integrity or abandoned wells within the Area of Review (AOR)⁹ which penetrate the injection or confining zone. The AOR for the site shall be defined within the permit in accordance with the requirements for the specific well class, formation, and local characteristics.

  • Well construction and monitoring requirements are set out in Section 3.2 and Section 4.1.2, and legacy offset and production wells contained within the delineated AOR which penetrate the injection or confining zone, must be evaluated (Section 3.2).

  • Migration out of the intended formation may also result from the migration up an existing or newly opened fault.  Faults should be mapped out prior to injection and fracture propagation should not intersect with active faults (Section 2). In addition, the formation of new faults must be monitored over the Project’s Crediting Period. 

  • Any releases from migration out of the intended storage complex within the storage complex must be deducted from the total CO₂ removal claimed by a project (Section 4.3).

• Bio-oil may react with surrounding storage complex rocks:

  • If low pH bio-oil (typically pH 2-3) is injected, it could induce reactions with or dissolution of surrounding reservoir rocks and confining layer, which could decrease durability by providing conduits for migration out of the storage complex. Research by Charm Industrial has shown that at 7 and 21-day bio-oil exposure to sandstone and dolomite, in bench scale  experiments (at 40^oC and 100PSI), result in varying degrees of reactivity with up to < 5% and < 3% weight loss for sandstone and dolomite respectively⁴. Limestone is expected to have a higher degree of degradation⁴. 

Section 2.0 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 4.2 acts to address and mitigate these potential risks to durability. Section 4.3 addresses accounting for any emissions associated with these risks. 

Monitoring of the injection, operations and project 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 UIC or equivalent permitting requirements as specified in the operating permit for the injection site issued by the relevant regulatory authority (e.g., EPA or the State to which EPA has delegated permit authority or equivalent entities in other jurisdictions outside of the USA). 

The subsurface monitoring approach developed and implemented by the Project Proponent shall address, via the permitting process and permit compliance, or by additional efforts and documentation:

• Storage complex and Site Characterization: The storage complex and AOR must be properly characterized and evaluated and that local and regional hydrogeology and leakage pathways have been identified. Measurements prior to injection may act as background measurements for models or for comparison with future measurements.

• Injection Site Construction and Performance: the proposed storage site and injection system must be properly designed, including design and specification of wellbore and well materials to ensure proper long term operation of the well when injecting biomass/bio-oil remains within the storage complex. 

• Injection System Operation & Monitoring: the Project Proponent must specify operating conditions and monitoring systems and approaches, such as allowable wellhead pressures, gas detection, and other systems to ensure that the injectate remains in the geologic formation, the formation and confining layer are not negatively impacted by operations, automatic safety precautions are in place to minimize potential for exceeding allowable operating conditions, and conditions can be monitored for compliance or deviation from requirements. Monitoring and reporting of operations will be in accordance with the relevant regulatory body. Any non-compliance must be reported to the Validation and Verification Body (VVB) and addressed with corrective actions (see Section 4.1.3.3 and the Isometric Standard).

• Closure and Post-Closure Requirements: Requirements for proper closure of the storage complex and injection facility, as well as post closure requirements and post-injection monitoring to ensure the injectate remains sequestered durably in the storage complex, the site is properly monitored and closed when the regulatory authority determines conditions have been met to demonstrate long-term storage.

Specifically, the following requirements must be met to ensure durable storage of biomass and bio-oil in the storage complex.

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 leakage pathways. This characterization should also include the following conditions to act as Baseline measurements against which to compare future monitoring and help with modeling. 

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:

• includes a sequestration zone of sufficient volume, porosity, permeability, and injectivity to receive and store the total anticipated volume of the injectate stream;

• includes a confining system free of transmissive faults and fractures and of sufficient extent and thickness to contain the injectate stream, displaced formation fluids and any gas generation. The confining system should be composed of a layered interval of low and moderate permeability rocks of sufficient thickness and structural integrity to prevent the migration of injectate or any gasses formed out of the storage complex. The confining system should also allow injection at proposed maximum pressures and volumes without initiating or propagating fractures in the confining zone(s);

• will not be impacted by, or induce as a result of the injection process, seismicity at levels that may inhibit the durability of biomass or bio-oil  storage. The Project Proponent will establish criteria within the relevant regulatory authority permit that require relevant seismic monitoring or preventive limitations on injection.

• Where applicable and required by the permit,  a “dissipation interval” with hydrogeologic properties sufficient to attenuate pressure created by bio-oil, formation fluid or any gasses formed migration to below the storage complex to limit downward overpressure propagation.

In addition, the Project Proponent must also characterize the following to assess the risk of leakage and for comparison to future measurements:

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 may 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.  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.

Potential leakage pathways must be evaluated through a combination of site characterization (Section 2) and realistic models that predict movement of injectate over time and locations where emissions might occur. This includes ensuring that all permitting requirements (Section 3.1) are met.

The injection site must have a current Class I or V UIC¹⁰ well permit or equivalent issued by the responsible authority for the location of the injection facility and storage complex. The permit must specifically identify biomass, bio-oil or an equivalent type of injectant, as acceptable injectants under the permit¹¹. Where a suitable permitting or regulation regime is not available, or suitable, Project Proponents must defer to EPA guidelines as a minimum and are required to outline the alternative use of EPA methods within their Project Design Document (PDD) submitted to the projects VVB prior to crediting.

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. 

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:

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

Casing, cement, tubing, packer, wellhead, valves, piping, or other materials used in the construction of 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. 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 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.

Monitoring of injection, system integrity as well as for subsurface migration is required in order to identify potential leakage pathways, measure leakage 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. 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 leakage, 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:

• Maximum allowable surface injection pressure (MASIP) at the injection wellhead that is allowed during injection operations to prevent fracturing of the confining layer, set according to the relevant regulatory body's permit. Injection operation pressures shall reflect any local regulatory agency requirements for formation fracture pressure as to ensure that the confining layer will not be fractured.
  • Installation and use of continuous recording devices to monitor injection pressure and the pressure on the annulus between the tubing and the long string casing
  • Monitoring and documentation of injection pressure must be performed and records maintained for review
• Maximum injection rate to monitor volumes injected, prevent induced seismicity or return of injectant
  • Installation and use of continuous recording devices to monitor injection rate and volume
  • Monitoring and documentation of injection rate must be performed and records maintained for review
• Limitations on composition of the injected fluid, including, but not limited to pH, density, temperature or other parameters, if relevant, to ensure injectant does not negatively impact the formation via inducing dissolution, reaction, or other degradation pathways, resulting in increased potential for bio-oil and fluid migration. Density in particular must be greater than that of the formation water.
  • Records of laboratory analyses and relevant permit limitations to demonstrate compliance must be maintained in accordance with the well permit and available for review.
• Analysis of the injectate stream with sufficient frequency to yield data representative of its chemical and physical characteristics. In addition, analysis of the injectate must demonstrate compliance with the well permit and be available for review. Injectate analysis should consist of the following parameters using industry standard or indicated methods and quality and properly calibrated equipment:
  • Total carbon content (for further details see Section 7.3.3.1 of the Biomass Geological Storage Protocol or Section 7.4.1.1 of the Bio-oil Geological Storage Protocol)
  • pH
  • Temperature
  • Chloride concentration or alternative determination as required by the regulator
  • Viscosity
  • Average solids concentrations
  • Density
  • Total acid number (TAN) (bio-oil)

For all injection and injectant (biomass/bio-oil) 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. Other useful measurements may include δ¹³C of the biomass/bio-oil compounds, major ions and biomass/bio-oil composition e.g., oxygen and nitrogen (via GC-MS).

For samples taken each injection batch, each individual batch of biomass/bio-oil that is injected 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 gas detectors (or equivalent sensors/imaging) with alarms and injection shut-off systems (e.g., automatic shut-off or procedures in place for manual shut off of injection/operation), including as required by the relevant permit monitoring for a gaseous release (CO₂, hydrocarbons or other gasses with GWP>1). If activated the operator must immediately investigate and identify as expeditiously as possible (or in accordance with permit requirements) the cause of the alarm or shutoff, and report the instance to the relevant regulatory body and to the validation and verification body (VVB).

System Integrity monitoring is required in order to ensure that the wells being used are not currently or likely to become a leakage pathway. Monitoring must include:

• Internal mechanical integrity of the wells must be tested upon well completion, when well construction is modified and at a cadence set by the relevant regulatory authority permit. These should ensure that well components meet the minimum standards for material strength and performance set by API, ASTM International, or equivalent, and include standard annular pressure tests and investigation for loss of mass, thickness, cracking, pitting, and other signs of corrosion .
• A demonstration of external mechanical integrity annually during operation and on a cadence specified by the relevant regulatory authority permit until the injection well is plugged
• A pressure fall-off test, quarterly.
• Continuous annulus pressure monitoring during injection.

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 gasses formed migration 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.

As applicable based on specific site conditions, formation type, and permit class, injection the Project Proponent could also include:

• Periodic geochemical monitoring of lowest USDWs (if required by the permit, as agreed in the monitoring plan with the regulating authority, or as seen appropriate by the Project Proponent) for groundwater quality and geochemical changes that may result from carbon dioxide or formation fluid movement through the confining zone(s). It is recommended that at a minimum fluids should be sampled for:
  • pH
  • Temperature
  • Density
  • Conductivity or other salinity measurement
  • Dissolved gas concentrations (i.e., CO₂, DIC)
  • Total Dissolved Solids (TDS)
• Surface displacement or subsidence, which can inform on pressure changes or geomechanical impacts from CO₂ injection, and when compared to reservoir models can indicate injection induced fracturing or changes in reservoir volume. Surface displacement should be monitored using one or more of the following techniques:
  • Satellite-based radar (SAR/InSAR). Satellite interferometry (InSAR) has been used to measure small displacements of the ground surface (of up to 2–3 cm) that have been related to the injection of CO₂ at depth
  • Surface- and subsurface-based tiltmeters
  • GPS instruments
• Surface CO₂ density and flux measurements to identify large point-source leaks, may be required to ensure compliance with regulations on potential risks to USDWs or by local regulators. Monitoring frequency and spatial distribution shall be determined using baseline data. Monitoring can be completed using one or more of the following methods:
  • Optical CO₂ sensors, such as airborne Infrared spectroscopy, non-dispersive infrared spectroscopy, cavity ring-down spectroscopy or LIDAR (light detection and ranging)
  • Eddy covariance (EC) flux measurement at a specified height above the ground surface
  • Portable or stationary carbon dioxide detectors
• Water table levels must be monitored if water from active aquifers is being used as part of the injection process.

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, N, 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., pressure fall off, simulation studies) methods:

• Continuous monitoring of reservoir temperature and pressure and any monitoring wells, if applicable, is required to show vertical containment within the storage complex. Temperature and pressure should be logged continuously, for example temperature could be measured through a fiber-optic distributed temperature sensing system.

• Monitoring of injectate plume confinement and far field containment using periodic (e.g.monthly), indirect measurements for example using a pressure fall-off test.

• Monitoring of pre-existing fractures and fracture development. Prior to injection step rate tests should be conducted to understand the fracture breakdown and fracturing pressures. During Operation, Pressure Fall Off tests should be done regularly to understand how the formation is responding to injection and look at induced fracture stability, including the closure and fracturing pressures that guide injection. Any deviations from simulations (see below) must be reported to Isometric, the VVB and regulating authority. Any major consistent deviations from simulations could result in an AOR re-evaluation, which may be performed based upon injection operations at the UIC Program Director's or equivalent discretion/request. In addition, fracture propagation should not be towards faults that could result in the migration of fluids above the confining layer.

• Monitoring of the composition of any gas recovered in the displaced brine (or monitoring wells or representative sampling locations when available) is required where applicable, when there is a detection of gasses from the cavern. Gas monitoring must include CO₂, CH₄ and VOCs emissions from the salt cavern via gas monitors with a resolution of at least 0.01 vol%. Results must be compared to baseline values obtained prior to injection. If concentrations above background are detected a sample must be taken to establish the chemical composition of the displaced gasses (including CO₂, CH₄, N₂, O₂ and VOCs) via lab analysis. Sampling frequency should be monthly. Gas formation monitoring could also be monitored using reservoir pressure and migration using quarterly advanced pressure transient analysis.

• A seismic monitoring program is required to ensure that any induced fracturing or injection does not cause seismicity that may have an impact on the confining layer and thus the long duration storage of biomass/bio-oil. This may be a site specific monitoring program or a national monitoring program (e.g., by the USGS). The area within the AOR of the injection facility and the area of the storage complex must be monitored for 2.7 magnitude¹² or greater seismic events to determine the presence or absence of any induced micro-seismic activity associated with all wells and near any discontinuities, faults, or fractures in the subsurface or any seismic activity.

• Reservoir modeling must be performed to estimate and locate the injectate as well as gas generation and migration. This must include pressure and fracture simulations and be done using software with an industry accepted methodology or where no such software is not available, a method of calculation shall be used that is justified and approved by the regulating authority. Fracture simulation modeling and analysis must provide estimates on fracture size and expected distribution including at minimum, fracture width, length and height. This 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 the fractures and injectate within storage complex. Uncertainty analysis is required around key variables in the simulation to ensure durability persists across a variety of scenarios within the realistic range of values. All parameters used within the models, their values and accuracy must be reported and submitted to Isometric and the VVB.

As applicable based on project- and site- specific conditions the Project Proponent should also:

• Include direct observation of the wells such as reservoir temperature, pressure, pH and conductivity, if monitoring wells are available. Monitoring should also focus on:
  • Identifying gaseous degradation products (CO₂, CH₄, VOCs) in monitoring wells that may indicate biomass/bio-oil degradation and/or migration. Results must be compared to baseline values obtained prior to injection (see Section 2).
  • Geochemical monitoring of the reservoir fluids to determine the behavior of the injectate and any gasses formed and their migration extent if monitoring wells are available. These measurements could include but are not limited to:
    • pH
    • Conductivity
    • Gas/dissolved gas composition including DIC ( to determine fluid saturation states as calculated by thermodynamic principles, to see if these conditions are conducive for mineralisation)
• Periodic mapping fluid locations using electrical methods (EM, IP, resistivity) as an independent check on fluid locations¹³

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.

If any leakage is 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 leakage 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 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:

• Observed migration of the plume or of any gasses formed is unexpected and suggests potential movement of injectate outside the intended formation
• Injectate migration into a zone above the storage complex
• Injectate plume or elevated pressure extend beyond analytical model expectation because any of the following has occurred:
  • an earthquake of magnitude 2.7¹² or greater within the AOR;
  • a new site characterization data which changes the model inputs to such an extent that the predicted injectate and/or pressure plume extends vertically or horizontally beyond what was originally predicted.

Further information on the risk and attribution of reversals, see Section 4.3.

The aim of this post-injection monitoring and the closure requirements (Section 4.5) 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) 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 4.5).

It is recommended that for post-injection monitoring 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 4.3. This monitoring therefore must focus on:

• Mechanical integrity of the injection well, and any monitoring wells if applicable, occurs annually for the first three years after injection ceasing and every five years until site decommissioning, to ensure they do not become a leakage pathway.
• Reservoir temperature and pressure.
• Indirect imaging or measurements of plume confinement or pressure front migration, if applicable.
• Pressure in the overlying formation and of the USDWs (where applicable) to identify and address any leakage pathways that arise.
• Identification of biogas from the degradation of the injectate.
• Reservoir modeling, where deemed appropriate by Isometric and/or the regulating body, based on monitoring data collected during post-injection monitoring to demonstrate the stability of the injectate and lack of plume or biogas migration in the formation that would present a risk to water sources or a potential reversal in the AOR. Any measured parameters should be compared to modeled predictions to help refine the model or identify possible risks.

In addition, the density contrast is the key mechanism that provides long-term durability of bio-oil storage. The density of bio-oil samples must be measured prior to each injection and compared to formation fluid values to ensure that bio-oil will sink upon injection. These measurements should be repeated before each new injection of bio-oil. Formation fluid samples will be acquired prior to bio-oil injection and compared to historical production data from the storage complex or nearby representative analogues. Density contrast is demonstrated by:

• Calculation according to the density contrast equation below:
  • ⍴_bio−oil​ > ⍴_{formation fluid} where ⍴ is density at reservoir conditions calculated
  • ⍴=m/V where m is mass and V is volume, calculated according to reservoir-specific conditions, such as pressure, temperature and salinity (and any other reservoir conditions relevant to a density calculation).
  • Bio-oil density will be calculated according to reservoir conditions (as above) using the measured surface density (measured following ASTM D 4052-22 or ASTM D7042-21a) before commencing injection. Formation fluid density will be calculated or measured using samples of the formation fluid collected prior to injection.

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 4.5), 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 4.5.

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. The reversal risk shall be determined on a project by project basis. This reversal risk will be reassessed when new scientific research and understanding arises.

Reversals will be accounted for by projects and the Isometric Registry as detailed in Section 5.6 of the Isometric Standard.

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

1. If the Project Proponent was the only entity injecting into a given storage complex, the Project Proponent will take on 100% of the reversal.
2. If the Project Proponent was one of multiple entities injecting into that storage complex, the Project Proponent will be allocated a percentage of the reversed CO₂ proportional to the mass of injected material. For example:
   • A storage complex has a total of 200t of material injected at the time when the reversal is detected (this information should be provided by the Operator).
   • The Project Proponent has injected 50t of material in that storage complex.
   • The amount of reversed CO₂ has been quantified to be 10t.
   • The Project Proponent must compensate for 25% (50/200) of 10t CO₂ = 2.5t of CO₂.

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

$CO_{2}e_{Monitoring}$ is the total quantity of GHG emissions resulting from the operations and activities associated with monitoring the geologic storage of CO₂ during the project operations, closure, and post closure periods. Emissions that occur during a reporting period, RP, are included directly and fully in that reporting period, and are not allocated across multiple reporting periods.

Emissions are calculated as:

$CO_{2}e_{Monitoring}$ = $CO_{2}e_{Energy,\ Monitoring}$ + $CO_{2}e_{Transportation,\ Monitoring}$ + $CO_{2}e_{Embodied,\ Monitoring}$ + $CO_{2}e_{Misc.,\ Monitoring}$ + $CO_{2}e_{Reversal}$

(Equation 1)

Where

• $CO_{2}e_{Monitoring}$ = the total GHG emissions associated with storage monitoring allocated to a given RP, in tonnes CO₂e
• $CO_{2}e_{Energy,\ Monitoring}$ = the total GHG emissions associated with energy consumption for monitoring activities, in tonnes of CO₂e, see Section 4.4.2.
• $CO_{2}e_{Transportation,\ Monitoring}$ = the total GHG emissions associated with transportation for monitoring activities, in tonnes of CO₂e, see Section 4.4.3.
• $CO_{2}e_{Embodied,\ Monitoring}$ = the total GHG emissions associated with embodied emissions from construction of monitoring equipment and facilities as well as use of consumables for storage monitoring activities, in tonnes of CO₂e, see Section 4.4.4.
• $CO_{2}e_{Misc.,\ Monitoring}$ = the total miscellaneous GHG emissions for a given, that cannot be categorized by CO₂e_{Energy, Monitoring}, CO₂e_{Transportation, Monitoring}, or CO₂e_{Embodied, Monitoring} in tonnes CO₂e.
• $CO_{2}e_{Reversal}$ = the total CO₂ reversal, in tonnes CO₂e. See Risk of Reversal.

Emissions that occur during a reporting period, $RP$, are included directly and fully in that reporting period, and are not allocated across multiple reporting periods.

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

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

Emissions associated with $CO_{2}e_{Energy,\ Monitoring}$, are associated with electricity or fuel use, during reporting period, $RP$. Examples of electricity usage for monitoring activities may include, but are not limited to:

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

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

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

Emissions related to transportation associated with any monitoring activities during reporting period, $RP$, such as:

• transportation of samples for lab analysis
• transportation of specialty monitoring or sampling equipment to site

It should be noted that transportation emissions for monitoring will likely be zero or very low, as such emissions will typically be accounted for in fully burdened Cradle-to-Grave emissions factors for equipment used in monitoring. Project Proponents should use caution and ensure double counting is not occurring between embodied emissions and transportation emissions accounted for here.

Emissions related to equipment, materials, and supplies manufacturing used during reporting period, $RP$,or amortized through allocation to a number of removals.

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

• Non-feedstock conversion process inputs or consumables:
  • gasses, reagents or other materials used for operation of monitoring equipment, analytical testing, calibration of monitoring equipment and on-site analyzers
  • water
  • gasses such as nitrogen used for process or instrumentation purges
  • consumable sampling equipment or supplies that are used in significant quantities
• Equipment:
  • monitoring wells and all associated materials (steel casing, concrete, etc.)
  • on-line analyzers, measurement equipment, or other such devices
  • pumps, piping, and related equipment installed for monitoring purposes
  • all related support structures and infrastructure, including steel platforms, framing, supports, etc. installed for monitoring purposes
  • buildings and associated equipment utilized for monitoring purposes(e.g., on-site laboratories)

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

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

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

The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities and for reporting any outside of the categories provided as $CO_{2}e_{Misc.,\ Monitoring}$.

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

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

Calculation of CO₂eReversal is included in Equation 1, but is covered separately to the GHG assessment. See Section 4.3.

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.

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:

• Utilize predictive modeling based on monitoring data collected during post-closure monitoring to demonstrate the stability of the injectate plume and lack of injectate or biogas migration in the formation that would present risk to water sources in the Area of Review.
  • Modeling must be validated by comparison to historical monitoring data.
  • Models must utilize site specific geochemistry and injectate characteristics from analyses required in Section 4.1.3.1, 4.1.3.2 and 4.2 of this Module.
  • Models must assess the potential plume extent after 50 years and demonstrate that the plume will not migrate beyond the AOR and will not impact drinking water sources nor cause other environmental harms.
• Utilize new methods as outlined in subsequent Protocol versions and as measurement and monitoring technologies advance.

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 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 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 complex 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.

All records associated with the characterization, design, construction, injection operation, monitoring, and site closure must be developed, reported in the project design document, to the VVB's and to proper authorities as required by the relevant regulatory authority permit.

All records must be maintained for a minimum of 10 years after well closure. All closure and post-closure monitoring records must be maintained by the Project Proponent for a minimum of 10 years after closure.

Isometric would like to thank Chris Holdsworth (University of Edinburgh) and Anhar Karimjee for contributing to this Module.

1. https://pubs.usgs.gov/wsp/2281/report.pdf ↩

2. https://advantekwms.com/resources/technical-papers-and-presentations/ ↩

3. 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. ↩

4. Bio-oil Sequestration as a Viable CDR Pathway, Charm Industrial, 2023 ↩ ↩² ↩³ ↩⁴

5. https://www.nrel.gov/docs/fy00osti/27613.pdf ↩

6. https://www.osti.gov/servlets/purl/1722957 ↩

7. 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. ↩

8. 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. ↩

9. 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. ↩

10.  Note that other well classes may be utilized, such as Class II wells, if site specific UIC well permits identify biomass as an acceptable injectant. However, Class II wells may not be utilized if the wells are also used for enhanced oil recovery (EOR or EOR+) activities. ↩

11. Wells must be permitted and not ‘authorized by rule’, and must consider the specific emplacement and durable storage of biomass in the storage complex. As of writing, the utilization of Class V wells in the USA should be limited to wells operating under the Other / Experimental category of Class V wells or other appropriate well type as approved by the UIC permitting authority. ↩

12. Cal. Code Regs., tit. 14, § 1724.14, “Pre-Rulemaking Discussion Draft 04-26-17 Updated Underground Injection Control Regulations,” (2017). ↩ ↩²

13.  Workshop on Induced Seismicity due to fluid injection/production from energy related applications. https://escholarship.org/uc/item/6rk229pv ↩