Biomass or Bio-oil Storage in Salt Caverns

This Module details durability and monitoring requirements for bio-oil and biomass storage in salt caverns.

Salt caverns have historically been used to store or dispose of a wide variety of materials including hydrocarbons, brine, industrial and even nuclear waste. Salt's viscoelastic properties make caverns nearly impermeable to emplaced materials, reducing the risk of migration. Additionally, under stress salt deforms slowly resulting in the cavern closing around the wastes over long time periods and specific cavern conditions, entombing them within the low permeability salt¹. The geometry of salt caverns influences their storage capacity, stability, and integrity. Homogeneous salt caverns are within salt domes or thick salt beds and are solely surrounded by salt. Their stability and integrity are based on the rock salt only. Inhomogeneous salt caverns are within bedded salts or salt breccias, their stability and integrity are based on the properties of rock salt and non-salt permeable structures.

This Module is applicable for bio-oil or biomass slurry emplacement into salt caverns that have been approved by the relevant permitting authority. Storage within salt caverns can occur when the salt cavern is no longer viable for high pressure natural gas cycling or compressed air storage, or other waste storage. The emplacement and storage of fluids and waste products into salt caverns has been occurring since the 1940s and 1950s respectively².

Bio-oil is a dark, viscous liquid typically between pH 2-3 (but up to 6), consisting of oxygenated hydrocarbon compounds^{3 4}. Prior to emplacement, the pH may be buffered and/or salinity raised as required by permitting. Bio-oil can have co-products like biochar mixed into it ahead of injection underground. Within this Module, we use the words ‘bio-oil’ and ‘bio-oil with biochar interchangeably. The storage of bio-oil in salt caverns is relatively new and has not been well studied and documented as of December 2023.

Biomass slurry is an organic waste (e.g., manure, food waste, agricultural waste, paper sludge) mixed with on-site brine. The slurry contains compounds like carbon, nitrogen, phosphorus, oxygen, hydrogen, sulfur, and trace elements found in the organic waste.

As both bio-oil and biomass (hereafter known as "the injectate") are expected to be denser than the surrounding subsurface brine in the cavern it is expected that they will sink to the bottom during emplacement. Displaced brine is pumped out of the cavern and injected back into a different subsurface reservoir. The durability of the injectate stored within salt caverns depends on the characteristics of the injectate, the salt and any bedded layers, and the interactions between the two being well defined and monitored. This, when coupled with capping and closure of subsurface reservoirs as per the U.S. EPA Underground Injection Control (UIC) or equivalent permitting requirements, removes the CO₂ stored within the injectate from the atmosphere for geological timescales^{5 6 7 8}.

This section outlines requirements for evaluating emplacement and storage, with a focus on cavern characterization, infrastructure construction and monitoring. The post-emplacement monitoring plan detailed in Section 3.2 acts to address and mitigate these potential risks to durability. Section 4.0 addresses accounting for any GHG emissions associated with monitoring the geologic storage of CO₂ during the project operations, closure, and post closure periods.

Monitoring of the emplacement cavern, and overlying formations and surface where applicable, must be completed to ensure that any emplaced material remains stored within the confines of the salt cavern and does not migrate outside of the cavern, nor result in decay of the injectate and subsequent re-emission as CH₄, CO₂ or other volatiles. The emplacement cavern, and overlying formations and surface where applicable, must be monitored in with this Module and any permitting requirements as specified in the operating permit for the salt cavern issued by the relevant regulatory body. This Module addresses minimum requirements for emplacement well design, construction, operation, and monitoring to ensure proper cavern storage design construction and monitoring to ensure durability of storage. Although typically these requirements will be addressed in the permit, the emplacement of bio-oil and biomass into caverns is a novel approach for which permitting decisions and requirements are still in development and may not be consistent based on the evaluation and development of permitting approaches by each responsible authority. Therefore, critical concepts and requirements are documented here for consistency and to ensure proper cavern storage design construction and monitoring to ensure durability of storage.

The subsurface monitoring approach developed and implemented by the Project Proponent or Operator (when the Project Proponent is not operating the cavern) must address:

• Salt Cavern Characterization: the proposed storage cavern, surrounding areas that could or would be affected by the salt cavern’s integrity, overlying formations and Area of Review⁹ (AOR) must have been adequately characterized to demonstrate cavern suitability for storage and containment of the injectate. If an AOR is not defined within the permit, the Project Proponent/Operator must define an AOR. See Section 2.2 for further details.
• Emplacement Infrastructure Construction and Performance: the proposed storage cavern infrastructure and emplacement system must be designed in accordance to the UIC or equivalent permit and relevant API and ISO standards (e.g., API standard 65- part 2 on "Isolating Potential Flow Zones During Well Construction"¹⁰), including design and specification of wellbore and well materials to ensure proper long term operation of the well when injecting and protection of the lowermost underground source of drinking water (USDW).
• Emplacement System Operation & Monitoring: the Operator must specify operating conditions and monitoring systems and approaches, such as gas detection, and other systems to ensure that the emplaced material remains in the cavern, the salt cavern is not negatively impacted by operations, automatic safety precautions are in place to minimize potential for exceeding allowable operating conditions, and conditions can be monitored for compliance or deviation from requirements. Reporting of operations will be in accordance with the UIC or equivalent governing body.
• Closure and Post-Closure Requirements: Requirements for proper closure of the salt cavern and emplacement facility, as well as post closure requirements and post-emplacement monitoring to ensure the injectate remains sequestered durably in the cavern and poses no net environmental harm, the cavern is properly monitored, and any non-compliance is addressed with corrective actions.

Specifically, the requirements in this Module must be met to ensure durable storage of injectate in the salt cavern. The Project Proponent is responsible for ensuring these requirments are met, inlcuding providing the data to Isometric.

Potential risks to expected durability of biomass and bio-oil are site specific and may include:

• Risk A: Emplacement may cause cavern wall dissolution.

  • Any liquid within the emplaced material that is below salt saturation may cause dissolution of the cavern walls. Prior to cavern emplacement, material must be salt saturated as required by the governing permitting regime. For example, salt crystals may be added commensurate to bio-oil water content and biomass may be mixed with displaced cavern brine to minimize salinity differences within the cavern and mitigate dissolution.
  • The low pH of bio-oil can induce reactions with the cavern infrastructure, which may decrease durability by providing conduits for migration out of the cavern. Mineral blankets can be used to protect the tubing string from continuous exposure to emplaced materials and/or the bio-oil buffered to a higher pH.

• Risk B: Emplacement may lead to a loss of cavern integrity, for example via pressure and/or temperature differentials which could lead to fluid expansion/reduction and fracturing on closure.

  • Differences in cavern pressure compared to the surrounding formation could result in the deformation of salt, for example via fracturing, salt creep or roof collapse. This could result in subsidence, the leaking of the injectate outside of the cavern and to USDWs/the atmosphere and/or a decrease in cavern volume. As the injectate will be denser than the brine it is replacing it is likely to increase the cavern stability. Any signs of pressure or temperature differentials must be monitored and emplacement/closure procedures adapted accordingly. The overlying strata can also provide support for the overburden reducing the risk of roof collapse.

• Risk C: Injectate may be converted to bio-gases within the cavern such as CO₂, CH₄, N₂, O₂, H₂S and VOCs(volatile organic compound).

  • The emplaced material could biodegrade to form CO₂, CH₄, N₂, O₂ and VOCs and other short-chain hydrocarbons. Microbial activity could also cause H₂S formation. Gas formation may increase the pressure within the cavern decreasing the stability. Any signs of gas formation should be monitored as part of the operation and post-emplacement monitoring plan (see Sections 3.1.3 & 3.2. Any gases produced will be considered removed because of the impermeable cavern walls and roof and well design preventing the migration of buoyant phases (such as biogas). Any releases of C bearing gasses from the salt cavern must be deducted from the net CO₂e removal (see Section 4.0).

• Risk D: Biomass/bio-oil emplacement results in leaks in emplacement, monitoring or legacy wells.

  • Biomass/bio-oil can damage integrity of any emplacement monitoring wells.

The emplacement cavern 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 and Section 3.7 of the Isometric Standard.

The Project Proponent must ensure that they meet the requirements of this Module. 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 by the Project Proponent to Isometric as part of the PDD. 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 by the Project Proponent.

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.
All projects are required to clearly report the regulations for which are utilized at the site, with any deviations from the relevant national/international standards outlined within the PDD upon submission to the relevant validation & verification body (VVB).

The cavern should be characterized in accordance with this Module and the permit application and approval requirements under the relevant regulations. Cavern characterizations must include evaluation of cavern chemistry and conditions, where required, to ensure compatibility of the injectate with the salt cavern.

As part of the permit application, it must be demonstrated, where applicable, that the cavern:

• Is of sufficient volume to receive the total anticipated volume of the injectate stream;
• Is free of transmissive faults and fractures and of sufficient extent and thickness to contain the emplacement volume, displaced cavern brines and any biogas generation;
• Has structural integrity (i.e., cavern walls are of an adequate thickness and extent and it is not in close proximity to other caverns or the salt boundary, no evidence of salt creep, salt has sufficient compressive and shear strength) such that it will prevent migration of the injectate, brine or biogas above the storage complex, towards the surface and atmosphere and/or USDWs;
• Low permeability and thickness of cavern to prevent vertical or lateral migration of the injectate, brine or biogas above the storage complex, towards the surface and atmosphere and/or USDWs;
• The Operator must also identify a suitable formation for displaced brine injection.

In addition, the Project Proponent must also characterize the parameters listed in Table 1 to assess the risk of leaks, develop the operation conditions for injection and monitoring plans, model the injectate behavior and for comparison to future measurements:

Table 1: List of cavern characterization requirements

Salt cavern characterization can be provided in the form of previous characterizations and historical data, as long as the requirements outlined within this Module are met.

The Project Proponent or Operator (when the Project Proponent does not operate the cavern) is required to demonstrate that there is an approved permit for displaced brine injection in place. It is a requirement that re-injection of the brine must occur within a closed system to avoid any contact and equilibration with the atmosphere, resulting in potential reversals. The Project Proponent is required to assess and quantify any potential reversals as a direct result of brine injection.

Cavern characterization is required to be reviewed every five years as part of The Project Crediting Period (see Isometric Standard) at a minimum, or at the regulators request, or when monitoring and operational conditions warrant, as indicated by a significant change in site conditions, injectate characteristics, or monitoring data. The review must include a comparison of pre-emplacement project assumptions to actual measured conditions including salt cavern capacity, the structural integrity of the cavern, and specific operating conditions observed during emplacement. Estimates revised with any acquired monitoring data should demonstrate that the planned emplacement volume will remain within the salt cavern until the end of the post-emplacement 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 or Operator (when the Project Proponent does not operate the cavern) must ensure that the emplacement well is constructed in compliance with the EPA UIC or equivalent permit. All documentation and records of well construction are required to be maintained and available for review, at any time during the project lifetime.

At a minimum, the Operator must ensure that any legacy wells which may exist within the delineated AOR have been evaluated and wells which pose a risk to durability are properly plugged prior to emplacement in order to:

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

Casing, cement, tubing, packer, wellhead, valves, piping, or other materials used in the construction of each well associated with The Project must have sufficient structural strength and be designed for beyond 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 the injectate and cavern brines (e.g., corrosion-resistant well casings) and must meet or exceed standards developed for such materials by API, ASTM, ISO, or comparable standards. Utilized standards are required to be clearly outlined within the project design document (PDD) submitted by the Project Proponent. The casing and cementing program must be designed to prevent the movement of fluids out of the sequestration zone and above the storage complex.

If pre-existing wells are being used for injection or monitoring, special considerations are necessary to ensure the integrity of the well and to prevent fluid migration along the borehole. These must be agreed and checked by the regulating body to determine construction and safety is consistent with well construction requirements. All checks and modifications must be recorded and all records kept. This must include the following:

• determining the integrity of the cement and casing.
• conducting any necessary action to repair defects.
• determining whether the existing well materials are adequate for the new function of the well.
• determining the diameter of the hole, any deviations from vertical, and any significant curvature or bends in the well should be compared with the size of the proposed monitoring equipment.
• existing well materials should be checked to ensure that they are compatible with fluids with which they will come into contact, such as carbon dioxide and carbon dioxide-rich brines if they are completed in the injection zone.
• any flaws in the casing or cement will need to be repaired.

Monitoring of emplacement, 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 or Operator (when the Project Proponent does not operate the cavern) is required to ensure that the emplacement facility complies with this Module and the well permit, including the development and implementation of the well operating plan as required by the permit. If the permit (for Projects within an approved permitting regime) or approved monitoring plan (for those outside of these jurisdictions) has different monitoring requirements to those stated here, please provide justification of any deviation within the PDD. The Project Proponent must monitor the composition of the injectate and ensure it complies with the relevant permits. All other monitoring is required by the cavern Operator (or Project Proponent if they are operating the cavern) to ensure all material emplaced into or produced from the cavern must be sampled and analyzed in accordance with the approved written waste analysis plan required by the authorizing agency. At a minimum, the permit and associated well operating plan must consider the following:

• Emplaced material must be gravity fed or emplaced at a surface pressure beneath that which is specified in the permit, ensuring the cavern does not become over-pressurized [B]. If emplacement is not gravity fed, emplacement pressure should be monitored continuously. Annulus pressure must be measured continuously.
• The volume of emplaced material must be monitored continuously. For example by monitoring the rate of injection or by using the weight of biomass/bio-oil emplaced and as well as the amount of water added where applicable [B].
• Limitations on composition of the injectate, including, but not limited to pH, temperature, conductivity/chloride concentration, if relevant, to ensure the injectate does not negatively impact the emplacement well, associated facilities and the cavern walls via inducing dissolution, reaction, or other degradation pathways, resulting in increased potential for migration of the emplaced material [A].
  • 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.
• Analysis of the injectate once per injection batch to yield data representative of its chemical and physical characteristics and demonstrate there is minimal effect on the cavern. In addition, analysis of the injectate must demonstrate compliance with the well permit and be available for review [A,B,C]. Injectate analysis should consist of the following parameters using industry standard or indicated methods using properly calibrated equipment:
  • Total C 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
  • Density
  • Total acid number (TAN) (bio-oil)
  • Water content (bio-oil)
  • Bio-oil consituents (bio-oil)

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 approved permit, where required.

For samples taken each emplacement batch, each individual batch that is emplaced 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 emplaced, samples should be taken for each emplacement batch.

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 for a gaseous release (CO₂, hydrocarbons, or other GHGs) and injection pump shutoff when maximum pressure is reached or maximum flow rate is exceeded. If the injectate is not in a gaseous phase, then detectors/alarms may be placed on any producing wells (e.g., brine producing wells/tanks for salt caverns) as an alternative to wellhead monitoring. Wellhead monitoring is then required if gas is detected and is found to be a result of biogas formation. If gas detection alarms are 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 Isometric [C].

• Corrosion monitoring of well materials must be performed and reported annually, for loss of mass, thickness, cracking, pitting, and other signs of corrosion, to ensure that well components meet the minimum standards for material strength and performance set by API, ASTM International, or equivalent. This could include but is not limited to corrosion coupons, flow loops or multi-finger calipers [D].
• A demonstration of external mechanical integrity annually [D]. This could include but is not limited to: an oxygen activation log, temperature log or sensors (e.g., distributed temperature sensors), or noise log. If one test indicates the potential loss of mechanical integrity, follow-up tests can verify and further characterize the potential pathways for leaks [A, D].

• Continuous monitoring of cavern pressure to ensure the cavern does not become overpressurized thus reducing the risks to the cavern integrity and for leaks [B].
• Periodic sonar surveys should also be conducted to quantify cavern fill and confirm containment as well as any salt creep that may be occurring (cavern geometry). At a minimum this should be done prior to emplacement, and when cavern capacity is expected to be at set points based on cavern specific data, for example at 33% and 66% full or at 50% full, and in agreement with regulators. The Operator may use an alternative but equivalent method than sonar surveys if agreed with the Project Proponent (if different to the Operator) and with the regulating body. This must be documented in the PDD [A,B].
• Cavern fill monitoring is required to provide information about the sump depth and its evolution, for example by comparison of the volume emplaced and cavern volume, that is confirmed quarterly by a depth to top of emplaced volume check.
• Analysis of the displaced brine stream once per injection batch using industry standard or indicated methods and quality and properly calibrated equipment [A,B,C]:
  • Volume (continuous e.g., by flow rate)
  • pH
  • Temperature
  • Conductivity/chloride concentration
  • Total organic carbon concentration
  • Bio-oil constiunets (if present/required by permit)
• Geochemical monitoring of USDWs may be required periodically (as agreed in the monitoring plan with the regulating authority) for groundwater quality and geochemical changes that may result from carbon dioxide or formation fluid movement through the confining zone(s):
  • pH
  • Density
  • TDS
• 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 gas monitors with a resolution of at least 0.01 vol%. 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)[C].
  • Results must be compared to baseline values obtained prior to emplacement, differences must be assessed by the Project Proponent to see if they are attributable and material to The Project. There are two options for determining a baseline, once the liquid petroleum gas (LPG) has been vented and gas measurements plateau following a spike from venting:
    • Once the LPG has been vented, if the gas measurements plateau and no gas is detected, the background will be zero and any gas later detected will be attributed to The Project.
    • Once the LPG has been vented, if there is still detectable gas during the gas measurement plateau, the baseline should be taken as the plateau measurement following LPG venting.
  • If no baseline was established after venting, any gas later detected will be attributed to The Project.
• Surface subsidence monitoring (every 2 years), for example using GPS or a set of benchmark levels on the storage cavern, is required and will be compared to baseline data and trends. This will be used to monitor for indication of salt movement (and volume variation) or cavern roof collapse. The surface elevation change of concern must be agreed with the regulating body prior to the start of emplacement [B].
• At a minimum, all projects are required to monitor for seismic activity caused by operations using regional seismic data and report any seismic events of magnitude 2.7¹² or greater [B]. An additional seismic monitoring program may be suggested at the discretion of the regulator or certified geologist in areas of increased seismic risk, where demonstrated that seismicity may have an impact on the salt cavern and durability of the injectate. This shall include deeper wireline or cemented subsurface geophones for microseismic monitoring and could be combined with at/near ground level stations as part of an integrated strategy. Seismic monitoring can be used to determine the presence or absence of any induced micro-seismic activity associated with all wells and near any discontinuities, faults, or fractures in the subsurface, or any seismic activity in the area within the AOR of the injection facility and the area of the storage reservoir of magnitude 2.7 or greater.

For all emplacement monitoring and analyses, sufficient samples must be analyzed to determine that the composition of the injectate is within specified parameters in the approved permit, where required. Each individual batch of injectate that is emplaced should be analyzed and characterized to ensure composition variation from batch to batch is accounted for. Samples should be from a well mixed and representative container of the injectate. Requirements for C content analysis are set out in the relevant Protocols.

If any leaks are detected from the cavern, the Project Proponent/Operators must undertake corrective measures as set out in their monitoring plan submitted and approved by the permitting authority. If the cavern is found to have lost integrity, the Operator must halt emplacement whilst they conduct an assessment to determine whether there are any leaks and whether the loss of containment and/or well mechanical integrity and/or cavern integrity can be repaired prior to recommencing operations. The amount of CO₂ lost must also be quantified and subtracted from the overall total of CO₂ stored.

Re-evaluations of the emplaced material must also be implemented when warranted based on observational or quantitative changes of the monitoring parameters of the salt cavern, including but not limited to:

• Loss of cavern or well integrity and migration of the injectate outside the salt cavern
• Materially elevated pressure/temperature

The Project Proponent/Operators must prepare an emergency reponse 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 lost must also be quantified and subtracted from the overall total stored.

Further information on the risk and attribution of reversals, see Section 4.0).

The aim of this post-emplacement monitoring is to prove beyond reasonable doubt that storage is expected to be durable on geologic timescales at which point the cavern can be closed Post-emplacement monitoring must focus on using a combination of direct (e.g., pressure, temperature) and indirect methods (e.g., sonar surveys, simulation studies) as discussed in Section 3.1.3 to confirm containment of the injectate and any biogas produced to ensure durability. The requirements in this section should be followed until the closure of the cavern (see Section 6.0).

The Project Proponent/Operators must follow any post-emplacement requirements of the local permitting regime, in addition to the following:

1. Continuous monitoring of the cavern pressure and formation fluid temperature [B]. Cavern fill must be recorded once at the end of operations. This can provide information regarding the cavern's natural closure characteristics and any ensuant pressure buildup, as well as information on mechanical integrity of the wellbore, salt creep-closure rate analysis, and flow rate calculation.
2. Monthly gas monitoring for emissions of CO₂, CH₄, N₂, O₂ and VOCs at the wellhead is required, where applicable and when gas volumes allow, until closure of the well [C]. If any emissions outside of the normal average baseline range for any of these gases occur, then further monitoring of gases should take place. Further monitoring entails measurements of:
   1. Concentrations (e.g., CO₂, CH₄, N₂, O₂ and VOCs), usually measured by GC-MS
   2. Stable isotope compositions of CO₂, CH₄ (δ¹³C of CO₂, CH₄ and δD of CH₄), usually measured by an isotope ratio mass spectrometer (IRMS), to determine the source of the bio-gas emissions. δ¹³C must be measured against the standard reference material Vienna Pee Dee Belemnite (VPDB). δD must be measured against the standard reference material Vienna Standard Mean Ocean Water (VSMOW).
3. Surface elevation and displacement monitoring, for example using GPS or SAR/inSAR, must be performed every 2 years and compared to baseline data and trends or reference points [B]. This will be used to monitor for indication of salt movement or cavern roof collapse.
4. Corrosion monitoring must be conducted annually, and external mechanical integrity testing must be conducted annually for the first three years after injection [D]. Annulus pressure must be measured monthly, but this frequency can be reduced if measurements are shown to be statistically invariable.
5. The total carbon content of the displaced brine must be measured once at the end of operations as an end-member sample for accurate carbon accounting [A]. The following measurements may also be required as per the permitting authority or certified geologist:
   • Formation fluid pH
   • Formation fluid conductivity/salinity
   • USDW pH
   • USDW density
   • USDW TDS

The reversal risk shall be determined on a project by project basis. There should be no reversals (as salt is impermeable) unless there is a loss of cavern or well integrity, and this technology does not yet have a documented history of reversals. This reversal risk will be reassessed every 5 years, aligning with the Crediting Period, or when new scientific research and knowledge are produced.

Reversals will be accounted for by projects and the Isometric Registry 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 emplaced in the cavern.

1. If the Project Proponent was the only entity emplacing into a given cavern, the Project Proponent will take on 100% of the reversal.

2. If the Project Proponent was one of multiple entities emplacing into that cavern, the Project Proponent will be allocated a percentage of the reversed CO₂ proportional to the mass of emplaced material. For example:

   • A cavern has a total of 200t of material emplaced at the time when the reversal is detected.
   • The Project Proponent has emplaced 50t of material in that salt cavern.
   • 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 reversals are determined to be a result of negligence by the Operator or Project Proponent, project crediting may be ceased.

$CO_{2}e_{Emissions}$ is the total greenhouse gas emissions associated with a given Reporting Period, $RP$, or batch, $n$.

Equations and emissions calculation requirements for $CO_{2}e_{Emissions}$, including considerations for monitoring activities, are set out in the relevant Protocol and are not repeated in this Module.

The Operator must ensure that all permit requirements associated with planning for, preceding with and monitoring of well or storage cavern closure are adhered to and documented as required by the permit. A Cavern Closure Plan must be prepared in accordance with the permit requirements. Site closure must follow this plan and any relevant regulatory jurisdiction requirements for site decommissioning. This must include plugging of any wells within the AOR.

CO₂ storage agreements with pore space owners will ensure activity in the storage cavern is prohibited for perpetuity following emplacement, ensuring that the injectate will not be subject to pressure disturbances (i.e, emplacement or production activities) in the salt cavern.

The Operator must monitor the cavern following emplacement completion to determine the three-dimensional extent of the injectate and cavern integrity and demonstrate that no injectate migration out of the salt cavern is occurring, as per the post-emplacement monitoring plan in Section 3.2, above. In addition, due to the emplacement of biomass and bio-oil being a nascent field, if they are emplaced into a cavern alongside another waste material, the long-term effect of the multiple waste types, their interaction and impact on abandonment, has not been investigated and will require stringent monitoring both during emplacement, post emplacement and closure. Post-closure monitoring, for example, surface subsidence monitoring, may be required by the permit and all requirements must be followed.

Prior to closure, an assessment must be completed to demonstrate that cavern integrity will be maintained (for example proving the absences of salt fracture generation) and the emplaced material can be considered stabilized, eliminating the risk of migration or release of the injectate or its degradation products from the cavern to the atmosphere. The cavern integrity assessment must be conducted in the following ways:

1. Measurement of Cavern pressure to ensure it is not pressurized. It must be demonstrated that any natural increase in pressure in the closed cavity due to long-term convergence does not exceed the fracture pressure.
2. Alternatively emerging technologies for measuring cavern integrity can be used, and will be outlined in subsequent Protocol versions and as measurement and monitoring technologies advance.

If the cavern integrity 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 emplaced material and salt cavern will be considered stabilized and additional monitoring post-closure may be discontinued if allowed under the applicable permit.

The long term stability of the cavern system should also be monitored by measuring surface movement over a period determined and agreed with the UIC or equivalents governing body and will be subject to change. The UIC or equivalents executive director or equivalent may extend the period of post closure monitoring if they determine that the well or cavern may endanger an underground source of drinking water or freshwater aquifer and subject to ongoing analysis.

All records associated with the characterization, design, construction, injection operation, monitoring, and cavern closure must be developed, reported in the Project design document, to the VVB 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.

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.These records must be available to be consulted by interested parties for future clarifications if needed.

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

Table A.2 Operational Monitoring Requirements

Table A.3 Post-Injection Monitoring Requirements

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:

• U.S. EPA Underground Injection Control (UIC)
• UK Environment Agency
• Saskatchewan Ministry of Energy and Resources.
• Alberta Energy Regulator (AER)

ASTM D5291-21 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants_. (2021, November). https://www.astm.org/standards/d5291

ASTM D373-21 Standard Test Methods for Determination of Carbon, Hydrogen and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke (2021, April). https://www.astm.org/d5373-21.html

Buzogany, R., Reveillere, A., Lampe, B., Borglum, S., Karimi-Jafari, M., Bernhardt, H., 2022. Abandonment of salt caverns: Phase 1: Gap Analysis. Solution Mining Research Institute Research Report 2022-1.

California Air Resources Board. (2018, August 13). Carbon Capture and Sequestration Protocol under the Low Carbon Fuel Standard. https://ww2.arb.ca.gov/sites/default/files/2020-03/CCS_Protocol_Under_LCFS_8-13-18_ada.pdf

Charm Industrial. (2023). Bio-oil Carbon Capture & Sequestration Protocol Under the LCFS. DRAFT.

Charm Industrial. (2023). FAQ | Fastest growing carbon removal technology. Charm Industrial. Retrieved June 14, 2023, from https://charmindustrial.com/faq

Diebold, J.P. (2000). A Review of the Chemical and Physical Mechanisms of the Storage Stability of Fast Pyrolysis Bio-Oils. https://www.nrel.gov/docs/fy00osti/27613.pdf

Energy Information Administration. (n.d.). Biomass explained - U.S. Energy Information Administration. EIA. Retrieved June 14, 2023, from https://www.eia.gov/energyexplained/biomass/

International Energy Agency. (n.d.). Insights Series 2015 - Storing CO2 through Enhanced Oil Recovery -- Analysis. IEA. Retrieved June 14, 2023, from https://www.iea.org/reports/storing-co2-through-enhanced-oil-recovery

International Organization for Standardization. (2006). ISO 14040:2006 Environmental management --- Life cycle assessment --- Principles and framework. https://www.iso.org/standard/37456.html

International Organization for Standardization. (2006). ISO 14044:2006 Environmental management --- Life cycle assessment --- Requirements and guidelines. https://www.iso.org/standard/38498.html

International Organization for Standardization. (2008). Evaluation of measurement data --- Guide to the expression of uncertainty in measurement (ISO JGCM GUM). https://www.iso.org/sites/JCGM/GUM/JCGM100/C045315e-html/C045315e.html?csnumber=50461

International Organization for Standardization. (2011). ISO 14066:2011 Greenhouse gases --- Competence requirements for greenhouse gas validation teams and verification teams. https://www.iso.org/standard/43277.html

International Organization for Standardization. (2017). ISO/IEC 17025:2017 General requirements for the competence of testing and calibration laboratories. https://www.iso.org/standard/66912.html

International Organization for Standardization. (2019). ISO 14064-2:2019. Greenhouse Gases - Part 2: Specification With Guidance At The Project Level For Quantification, Monitoring And Reporting Of Greenhouse Gas Emission Reductions Or Removal Enhancements. ISO. https://www.iso.org/standard/66454.html

International Organization for Standardization. (2019). ISO 14064-3:2019. Greenhouse gases --- Part 3: Specification with guidance for the verification and validation of greenhouse gas statements. ISO. https://www.iso.org/standard/66455.html

Isometric. (n.d.). Isometric --- Glossary: Defining the terms that appear regularly in our work. Isometric. https://isometric.com/glossary

Kansas Department of Health and Environment. Underground Hydrocarbon Storage Program. Retrieved November 15, 2023, from https://www.kdhe.ks.gov/315/Underground-Hydrocarbon-Storage-Program

Matthews, J.B.R. (Ed.). (2018). IPCC, 2018: Annex I: Glossary. In: Global Warming of 1.5°C. An IPCC Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of... Cambridge University Press. https://doi.org/10.1017/9781009157940.008

Methodology for assessing the quality of carbon credits, Version 3.0. (2022, May). https://carboncreditquality.org/methodology.html

National Renewable Energy Laboratory. (2016). Quantification of Semi-Volatile Oxygenated Components of Pyrolysis Bio-Oil by Gas Chromatography/Mass Spectrometry (GC/MS) Laboratory Analytical Procedure (LAP). https://www.nrel.gov/docs/fy16osti/65889.pdf

National Renewable Energy Laboratory. (2021, October 7). Determination of Carbon, Hydrogen, Nitrogen, and Oxygen in Bio-Oils Laboratory Analytical Procedure (LAP). https://www.nrel.gov/docs/fy22osti/80967.pdf

National Renewable Energy Laboratory. (2022). Corrosivity Screening of Pyrolysis BioOils by Short-Term Alloy Exposures Laboratory Analytical Procedure (LAP). https://www.nrel.gov/docs/fy22osti/82631.pdf

National Renewable Energy Laboratory. (2022). Elemental Analysis of Bio-Oils by Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) Laboratory Analytical Procedure (LAP). https://www.nrel.gov/docs/fy22osti/82586.pdf

Pereira, J.C., 2012. Common Practices -- Gas Cavern Site Characterization, Design, Construction, Maintenance, and Operation. Solution Mining Research Institute, Research report RR2012-03.

Sandalow, D., Aines, R., Friedman, J., McCormick, C., & Sanchez, D. (2020, October 2). Biomass Carbon Removal and Storage (BiRCS) Roadmap. https://www.osti.gov/servlets/purl/1763937

Schmidt, H., Anca-Couce, A., Hagemann, N., Werner, C., Gerten, D., Lucht, W., & Kammann, C. (20118, August 17). Pyrogenic carbon capture and storage. GCB Bioenergy, 11(4), 573-591. https://onlinelibrary.wiley.com/doi/full/10.1111/gcbb.12553

Society of Petroleum Engineers. (2020, April 13). Enhanced oil recovery (EOR) - PetroWiki. PetroWiki. Retrieved June 14, 2023, from https://petrowiki.spe.org/Enhanced_oil_recovery_(EOR)

Stas, M., Auersvald, M., Kejla, L., Vrtiska, D., Kroufek, J., & Kubicka, D. (2020, May). Quantitative analysis of pyrolysis bio-oils: A review. TrAC Trends in Analytical Chemistry, 126. https://www.sciencedirect.com/science/article/abs/pii/S0165993620300868

U.S. Environmental Protection Agency. (2014). Test Methods for Evaluating Solid Waste: Physical/Chemical Methods Compendium (SW-846). https://www.epa.gov/hw-sw846/sw-846-compendium

1. Buzogany, R., Reveillere, A., Lampe, B., Borglum, S., Karimi-Jafari, M., Bernhardt, H., 2022. Abandonment of salt caverns: Phase 1: Gap Analysis. Solution Mining Research Institute Research Report 2022-1. ↩

2. Thoms and Gehle- A brief history of salt cavern use. ↩︎ ↩

3. https://www.nrel.gov/docs/fy22osti/82586.pdf ↩︎ ↩

4. https://www.ieabioenergy.com/wp-content/uploads/2019/09/Task-39-Drop-in-Biofuels-Full-Report-January-2019.pdf ↩

5. Dusseault, M.B., Rothenburg, L., Bachu, S., 2002. Sequestration of CO2 in Salt Caverns. Journal of Canadian Petroleum Technology. https://doi.org/10.2118/2002-237 ↩

6. Davidson, B.C., Dusseault, M.B., 1997. Salt Solution Caverns for Petroleum Industry Wastes. SPE/EPA Exploration and Production Environmental Conference. https://doi.org/10.2118/37889-MS ↩

7. Duyvestyn, G.M., Davidson, B.C., Dusseault, M.B., 1998. Salt Solution Caverns for Petroleum Industry Toxic Granular Solid Waste Disposal. SPE/ISRM Rock Mechanics in Petroleum Engineering. https://doi.org/10.2118/47250-MS ↩

8. Davidson, B.C., Dusseault, M.B., Lemieux, B., 1997. Design And Management Of Salt Solution Caverns For Toxic Waste Disposal. https://doi.org/10.2118/97-151 ↩

9. Area of Review (AOR) is the representation of the cavern extent on the ground surface; a surface delineation of subsurface pressure influence resulting from emplaced materials ↩︎ ↩

10. API Standard 65- part 2 ↩︎ ↩

11. Influence Area is the area defined for subsidence monitoring by the regulatory agency or operator, if not otherwise specified in the permit ↩

12. 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. ↩