Biogenic Carbon Capture and Storage

This Protocol provides the requirements and procedures for the calculation of net CO₂ equivalent (CO₂e) removals from the atmosphere via Industrial Process Biogenic Carbon Capture and Storage (Bio-CCS). This Protocol is developed for application to Bio-CCS processes or combinations of processes (e.g., solid sorption,¹ liquid solvent,² membrane processes,³ electrochemistry,⁴ etc.) in which a cradle-to-grave GHG Statement can be accurately applied and in which the CO₂ captured is stored via physical⁵ or chemical⁶ trapping mechanisms for > 1000 years.

The Protocol ensures:

• Consistent, accurate procedures are used to measure and monitor all aspects of the process required to enable accurate accounting of net CO₂e removal;
• Consistent system boundaries and calculations are utilized to quantify net CO₂e removal;
• Requirements are met to ensure the CO₂ removals are additional; and
• Evidence is provided and verified by independent third parties to support all net CO₂e removal claims.

Specific standards and Protocols which are utilized as the foundation of this Protocol and for which this Protocol is intended to be fully compliant with are as follows:

• Isometric Standard
• 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

Additional reference standards that inform the requirements and overall practices incorporated in this Protocol include:

• ISO 14064-3: 2019 – Greenhouse Gases – Part 3: Specification with Guidance for the verification and validation of greenhouse gas statements
• ISO 14040: 2006 - Environmental Management - Life Cycle Assessment - Principles & Framework
• ISO 14044: 2006 - Environmental Management - Life Cycle Assessment - Requirements & Guidelines

This Protocol was developed based on the current state of the art and publicly available science regarding Bio-CCS^7,8,9. As Bio-CCS is still a developing approach to carbon dioxide removal (CDR) with ever-expanding published literature, this Protocol incorporates requirements that may be more stringent than other available regulations or Protocols. The approach taken here may be altered in future versions of the Protocol in-line with advancements in the available technology and published research.

This Protocol applies to projects that capture biogenic CO₂ at a point-source, resulting from processing of an eligible biomass feedstock as outlined in the Biomass Feedstock Accounting Module v1.3, and store this CO₂ with >1000 years durability via physical or chemical trapping mechanisms laid out in a relevant CO₂ Storage Module (see Section 9). Examples of applicable point-sources include, but are not limited to, biomass-fired power plants, biomass-fired combined heat and power (CHP) facilities, bio-hydrogen production, biogas plants, and Energy-from-Waste (EFW) facilities.

Projects which utilise waste feedstocks where biogenic and fossil carbon is inseparable are only eligible if:

• The biogenic fraction of the feedstock is eligible & accounted for within the Biomass Feedstock Accounting Module v1.3.
• The feedstock as a whole accounts for market leakage related emissions according to Section 4 of the Biomass Feedstock Accounting Module v1.3 for requirements.
• The feedstock as a whole complies with the Sustainability Criteria according to Section 2.1 of the Biomass Feedstock Accounting Module v1.3, using SC6.

Projects which utilise waste feedstocks where biogenic and fossil carbon is inseparable must demonstrate that there is a robust waste management hierarchy that ensures only unrecyclable waste is incinerated.

Projects which co-fire biomass with fossil fuels, or those using waste feedstocks where biogenic and fossil carbon is inseparable, must use an emission factor for the used mass of fossil fuels that accounts for the full upstream and combustion emissions.

If the fossil CO₂ is captured alongside the biogenic carbon, quantified according to the requirements in Section 8.2.1.1, and (barring unavoidable CO₂ leaks) is transported to the same storage reservoir as the biogenic CO₂, then Projects may use an emission factor for the fossil fuel which considers only the upstream emissions and excludes combustion emissions.

Whether emitted fossil CO₂ is considered a Project emission is dependent on the baseline scenario according to the guidelines in Section 7: System Boundary and Project Baseline, Appendix A: Guidance for Handling Fossil CO₂ and Appendix B: Baselines.

Additionally, Projects where more than 5% of feedstocks by mass are fossil fuels must provide a justification for the necessity of these feedstocks within the context of the carbon dioxide removal (CDR) Project at validation if applicable to the whole Project lifetime, or at verification if related to a specific Crediting Period only, subject to agreement with Isometric. Isometric reserves the right to not Credit Removals attributed to a given Reporting Period of a Project that has violated this guardrail without appropriate justification.

The Project Proponent must consider environmental and social impacts from processes that comprise part of the Project. The Project Proponent must provide evidence that the Project will do no net environmental or social harm by complying with Section 3.7 of the Isometric Standard as well as the following requirements:

• CO₂ interim storage, transport containers and pipelines must have monitoring systems in place to detect and identify potential CO₂ leaks, including audible alarms and regular monitoring or remote access to alarm notifications by Project Proponent staff following national/international regulations¹⁰ (see the relevant storage modules for more information).

• The Project Proponent must have a CO₂ leak response plan in place that complies with local or national requirements¹⁰ and covers the Area of Review (AOR). This plan must be shared with local communities and first responders in temporary holding, pipeline, and storage locations.

• The Project Proponent must document emissions of solvents and/or sorbents from the Bio-CCS project and demonstrate that emissions of the following types are below regulatory limits where applicable based on solvent and/or sorbent chemistry:

  • Amines (volatilized or in aerosol form);
  • Ammonia;
  • Volatile organic compounds (VOCs);
  • Nitrosamines and nitramines;
  • Particulate matter (solid sorbents); and
  • Other hazardous substances (as defined by the authority of the geography where the Project is located or the most stringent of relevant standards worldwide, for example by the EPA) that may be released as a result of sorbent or solvent degradation, volatilization, or aerosolization.

• Emission levels of solvents and/or sorbents must be demonstrated by using, where possible and reasonable, national or international standard test and sampling methods (i.e., NIST, ASTM, EPA), and should be completed by a qualified testing organization. Project Proponents must keep such records on file and must repeat testing when substantial changes to solvent or sorbent formulations occur or substantial changes in operating conditions occur that may impact emissions.

• Project Proponents must comply with all health and safety procedures as required by the authority of the geography where the Project is located or the most stringent of relevant standards worldwide. Proponents must demonstrate that they have addressed any specific hazards associated with the use of the proposed sorbent or solvent.

• Project Proponents must demonstrate that a social risk assessment has been conducted. This must consider environmental and social justice issues for the selected storage site, including a robust Stakeholder engagement program and considerations of any direct or indirect impacts on local communities or indigenous people, including livelihoods, ancestral knowledge and cultural heritage in line with the applicable human rights laws and United Nations declarations.

• Demonstrate a risk assessment and mitigation plan for safeguarding working conditions, especially regarding safe handling and transportation of solvents/sorbents as well as workers operating the capture and storage facility.

• The Project Proponent must monitor water consumption and water stress, in addition to necessary mitigation activities in place to ensure water neutrality.¹¹

The incineration of municipal solid waste (MSW) can carry a higher risk of pollution because heterogeneous feedstocks vary in composition and may contain trace contaminants. As a result, proper handling of waste and by-product outputs is essential.

Projects involving the incineration of MSW must demonstrate that the incineration facility complies with all relevant national, regional, and local environmental regulations for responsible waste handling, such as the EU Waste Incineration Directive (WID) and the Industrial Emissions Directive (IED), or an equivalent standard applicable to the Project's location.

If no suitable regional standard exists, Project Proponents are required to demonstrate that the facility follows international waste incineration best practice frameworks, including appropriate treatment of the following waste streams:

Typically the largest fraction of the output mass, bottom ash is typically composed of mineral residues, metals and potentially some small amount of uncombusted organic matter. Separation of the metals and suitable treatment to enable recycling/reuse is recommended. Project Proponents must establish an end-use/disposal of the ash, such as: recycling (separation of ferrous and non-ferrous metals); and/or treatment of the ash to enable reuse as Incinerator Bottom Ash Aggregate (IBAA) in construction. If bottom ash is sent to landfill as non-hazardous waste, Project Proponents must provide justification that there is no risk of hazardous leaching (for example, through EN 12457-2 or EN 14405 testing).

Fly ash typically comprises up to 5% of the original feedstock mass, consisting of fine particles captured from the flue gas, often with high concentrations of heavy metals, dioxins and furans. Both waste residues are considered hazardous waste. As such, Project Proponents must propose an appropriate method of disposal, for example by sending to a hazardous waste facility, or taking additional steps to stabilize the fly ash, using physical or chemical binders.

Project Proponents must use best available techniques to monitor and reduce flue gas emissions in compliance with the EU Industrial Emissions Directive (IED) and the limits detailed in EU Directive 2010/75/EU Annex VI Part 3, or equivalent local legislation.

Persistent Organic Pollutants (POPs), such as dioxins and furans, may be present in mixed waste material. If released to the environment, POPs can accumulate in living organisms and pose risks to human health and ecosystems. The high combustion temperature of incineration facilities leads to the destruction of POPs.

To reduce the prevalence of POPs, the flue gas must have a residence time of at least two seconds at homogeneous temperatures > 850 °C in the post-combustion zone. Temperature data must be reported alongside other data during a verification.

In addition, Project Proponents must propose a method for monitoring halogen content in any feedstock containing both fossil and biogenic carbon. Should the halogen content determination result in > 1%, the flue gas must have a residence time of at least two seconds at homogeneous temperatures > 1100 °C in the post-combustion zone instead.

The following topics are covered briefly in this Protocol due to their inclusion in the Isometric Standard, which governs all Isometric Protocols. See in-text references to the Isometric Standard for further guidance.

For each specific Project to be evaluated under this Protocol, the Project Proponent must document Project characteristics in a Project Design Document (PDD) as outlined in Section 3.2 of the Isometric Standard. The PDD will form the basis for project verification and evaluation in accordance with this Protocol, and must include consideration of processes unique to Bio-CCS, for example:

• a high-level process diagram detailing the key inputs, outputs and process flow through each Project stage;
• Documentation of additionality of CCS, and non-additionality of co-product production facilities not included in the Project boundary;
• GHG emissions associated with solvent/sorbent use and safe disposal; and
• Purity and concentration of CO₂ to be injected/stored.

Projects must be validated and project net CO₂e removals verified by an independent third party consistent with the requirements described in this Protocol as well as in Section 4 of the Isometric Standard.

The Validation and Verification Body (VVB) must consider following requisite components:

1. Verify that storage sites adhere to the requirements listed in the relevant storage module.
2. Verify that the quantification approach and monitoring plan adheres to requirements of Section 8, including demonstration of required records.
3. Verify that the Environmental & Social Safeguards outlined in Section 5 are met.
4. Verify that the Project is compliant with requirements outlined in the Isometric Standard.

The threshold for Materiality, considering the totality of all omissions, errors and mis-statements, is 5%, in accordance with Section 4.3 of the Isometric Standard.

Verifiers should also verify the documentation of uncertainty of the GHG Statement as required by Section 2.5.7 of the Isometric Standard. Qualitative Materiality issues may also be identified and documented, such as:¹²

• Data and document control issues that erode the verifier’s confidence in the reported data;
• Poorly managed documented information;
• Difficulty in locating requested information; and
• Noncompliance with regulations indirectly related to GHG emissions, removals or storage.

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 the first Validation or Verification of a Project, to the capture and (if applicable) storage site. Verifiers 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 occur at least once during each Project Validation. Additional site visits may be required if there are substantial changes to field operations over the course of a Project's Validation period, or if deemed necessary by Isometric or the VVB. Site visit plans are to be determined according to the VVB's internal assessment, in consultation with Isometric.

VVBs must comply with the requirements defined in Section 4 of the Isometric Standard. In addition, teams should maintain and demonstrate expertise associated with the specific technologies of interest, including solvent/sorbent chemistry, electricity procurement and heat/power generation and the relevant CO₂ storage technology.

Competency must be demonstrated in accordance with Isometric's VVB policy, for example based on the relevant sectoral scope accreditations in IAF MD 14, or another demonstration of relevant expertise for this Protocol and the selected storage module(s).

CDR via Bio-CCS is often a result of a multi-step process (such as capture, desorption, CO₂ transport, CO₂ temporary holding, the CO₂ injection process, etc.), with activities in each step sometimes managed and operated by different operators, companies, or owners. When there are multiple parties involved in the process (e.g., if capture and storage are undertaken by different entities), and to avoid double counting of CO₂e removals, a single Project Proponent must be specified contractually as the sole owner of the Credits. Contracts must comply with all requirements defined in Section 3.1 of the Isometric Standard.

The Project Proponent must be able to demonstrate additionality through compliance with Section 2.5.3 of the Isometric Standard. The baseline scenario and counterfactual utilized to assess additionality must be project-specific, and are described in Section 7.2 of this Protocol.

Additionality determinations should be reviewed and completed every five years (aligned with the Crediting Period, at a minimum, or whenever project operating conditions change significantly, such as the following:

• Regulatory requirements or other legal obligations for project implementation change or new requirements are implemented; or
• Project financials indicate Carbon Finance is no longer required, potentially due to, for example:
  • Sale of co-products that make the business viable without Carbon Finance; or
  • Reduced rates for capital access.

Any review and change in the determination of additionality should not affect the availability of Carbon Finance and Verified Credits for the current or past Crediting Periods, but if the review indicates the Project has become non-additional, this will make the Project ineligible for future Credits.¹³

The uncertainty in the overall estimate of the net CO₂e removal as a result of The Project must be calculated and transparently presented. The total net CO₂e removed over a Reporting Period ($RP$; see Section 8) for a Project, $CO_2e_{Removal,\ RP}$, must be conservatively determined, based on the requirements outlined in Section 2.5.7 of the Isometric Standard.

Projects must report a list of all input variables used in the net CO₂e removal calculation and their uncertainties, including:

• Emission factors utilized, as published in public and other databases used;
• Values of measured parameters from process instrumentation, such as metered heat and electricity usage, sorbent/solvent replacement periods and other equipment considerations;
• Laboratory analyses, including that required by selected storage module(s), which could include analysis of carbon content and purity of injected CO₂, CO₂-containing injectants or carbonated minerals; and
• Summary of data handling, processing, and error propagation approach.

The uncertainty information should at least include the minimum and maximum values of a variable. More detailed uncertainty information should be provided if available, as outlined in Section 2.5.7 of the Isometric Standard.

In addition, a sensitivity analysis that demonstrates the impact of each input parameter’s uncertainty on the final net CO₂e uncertainty must be provided. Details of the sensitivity analysis method must be provided so that the results can be re-created. Parameters may be omitted from a full uncertainty analysis if a Sensitivity Analysis can demonstrate that the parameter contributes to <1% change in removal. For all other parameters, information about uncertainty must be specified.

In accordance with Section 3.8 of the Isometric Standard, all evidence and data related to the underlying quantification of the net CO₂e removal will be available to the public through Isometric's platform. This includes:

• Project Design Document
• GHG Statement
• Measurements taken
• Emission factors used
• Scientific literature used

The Project Proponent can request certain information to be restricted (only available to authorized Buyers, the Registry, and VVB) where it is subject to confidentiality. This includes emission factors from licensed databases. However, all other numerical data produced or used as part of the quantification of net CO₂e removal will be made available.

The scope of this Protocol includes GHG sources, sinks and reservoirs (SSRs) associated with a Bio-CCS Project.

A cradle-to-grave GHG Statement must be prepared encompassing the GHG emissions relating to the activities outlined within the system boundary.

GHG emissions and removals associated with the Project may be direct emissions from a process or storage system, or indirect emissions from combustion of fuels, electricity generation, or other sources. Emissions must include all GHG SSRs within the system boundary, from the construction or manufacturing of each physical site and associated equipment, closure and disposal of each site and associated equipment, and operation of each process (CO₂ capture process, CO₂ transportation, storage, and monitoring), including embodied emissions of equipment and consumables used in the Project. The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities.

Any emissions from sub-processes or process changes that would not have taken place without the CDR Project must be fully considered in the system boundary. Any activity that ultimately leads to the issuance of Credits should be included in the system boundary. Biomass feedstock emissions must be calculated as outlined in Section 3 of the Biomass Feedstock Accounting Module v1.3. This allows for accurate consideration of additional, incremental emissions induced by the carbon removal process.

The GHG Statement boundary must include all relevant GHG SSRs controlled, related and affected by the Project, including but not limited to the SSRs set out in Figure 1 and Table 1. If any GHG SSRs within Table 1 are deemed not appropriate to include in the system boundary, they may be excluded provided that robust justification and appropriate evidence is provided in the PDD.

Figure 1. Process flow diagram showing system boundary for Bio-CCS projects

Table 1. Scope of activities to be included in the system boundary for Bio-CCS projects

Miscellaneous GHG emissions are those that cannot be categorized by the GHG SSR categories provided in Table 1. The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities and must report any outside of the SSR categories identified as miscellaneous emissions.

Emissions associated with The Project's impact on activities that fall outside of the system boundary of The Project must also be considered. This is covered under Leakage in Section 8.2.3.4.

In line with the GHG Accounting Module v1.0, the Project must:

• Consider all GHGs associated with SSRs, in alignment with the United States Environmental Protection Agency’s definition of GHGs which includes: carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O) and fluorinated gasses such as hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF₆) and nitrogen trifluoride (NF₃). For CO₂ stored, only CO₂ shall be included as part of the quantification. For all other activities all GHGs must be considered. For example, the release of CO₂, CH₄, and N₂O is expected during diesel consumption;
• Quantify emissions in tonnes CO₂ equivalent (t CO₂e) using the 100-year Global Warming Potential (GWP) for the GHG of interest, based on the most recent volume of the IPCC Assessment Report (currently the Sixth Assessment Report); and
• Consider Materiality of SSRs in line with Isometric requirements.

Bio-CCS may have additional impacts on GHG emissions beyond the scope of this Protocol, that are not already associated with marketable co-products. For example, providing a source of secondary low carbon heat or electricity, avoiding landfill emissions and reducing waste transport emissions. These potential impacts are not included in this conservative GHG accounting framework.

The baseline scenario for a Bio-CCS Project is dependent on whether the CCS aspect of the Project is part of a new-build facility, or a retrofit to an existing facility:

• New-build: The baseline scenario assumes that all activities associated with the Bio-CCS Project and the wider facility do not take place and no associated infrastructure is built, unless it is eligible to draw a narrow system boundary through EC3 in Section 8.2.4.4.
• Retrofit: The baseline scenario assumes that the activities associated with the Bio-CCS component of the wider facility do not take place and no additional infrastructure associated with CCS is built.

See Appendix B: Baselines for further guidance on constructing a Project baseline.

The counterfactual is any CO₂ stored in the biomass feedstock that would have remained durably stored in the biomass feedstock in the absence of the Project, in addition to any CO₂ that would have been durably stored by the selected storage technology.

• Biomass counterfactual: If the CO₂ would have remained stored in the biomass in the absence of the CDR Project, it is considered ineligible biomass, and is therefore not eligible to count towards Crediting. The Biomass Feedstock Accounting Module v1.3 sets out requirements for establishing ineligible biomass as part of the Counterfactual Storage Eligibility Criteria, and includes details for quantification of $CO_2e_{Counterfactual}$.
• Storage counterfactual: The storage counterfactual of qualifying projects is considered to be zero unless a counterfactual scenario is required in the applicable storage module. For example, geological sequestration of fluidic CO₂ typically has zero counterfactual, but mineralisation of CO₂ must consider the counterfactual scenario of any mineralisation of CO₂ that would occur in the absence of the Project.

Bio-CCS systems are typically operated continuously, with captured CO₂ being transported and durably stored using a variety of potential processes. Due to the continuous nature of Bio-CCS systems, the equations used to calculate removals will pertain to all net emissions occurring over an interval of time. This unit of time is defined as the Reporting Period, $RP$, which is the time period during which net CO₂e removals are claimed by the Project Proponent and submitted for verification. The total net CO₂e removal is written hereafter as $CO_2e_{Removal}$.

The following sections outline the process for calculating the net CO₂e removed for each Reporting Period based on total mass stored during that period, written hereafter as $CO_2e_{Removal,\ RP}$.

Net CO₂e removal for a process utilizing Bio-CCS must be calculated as follows for a Reporting Period, $RP$:

$$CO_2e_{Removal,\ RP} = CO_2e_{Stored,\ RP}\ –\ CO_2e_{Counterfactual,\ RP} -\ CO_2e_{Emissions,\ RP}$$

(Equation 1)

Where;

• $CO_2e_{Removal,\ RP}$ = total net CO₂e removed from the atmosphere over a given $RP$, in tonnes CO₂e.
• $CO_2e_{Stored,\ RP}$ = the total biogenic CO₂ removed from the atmosphere and durably stored over the $RP$, in tonnes CO₂e. See Section 8.2.1.
• $CO_2e_{Counterfactual,\ RP}$ = the total counterfactual CO₂ removed from the atmosphere and durably stored in the absence of the Project over the $RP$, in tonnes CO₂e. See Section 8.2.2.
• $CO_2e_{Emissions,\ RP}$ = the total GHG emissions associated with the $RP$, in tonnes of CO₂e. See Section 8.2.3.

It should be noted that any potential reversals of CO₂ storage in the final storage location occur after Credits have been issued so are not included in this equation. See Section 5.6 of the Isometric Standard for further information. Risk of reversal information is given in Appendix D: Risk of Reversal Questionnaire, with further information provided within the relevant storage Module.

CO₂e_Stored represents the cumulative total CO₂ sequestered in all durable storage reservoirs over a Reporting Period. It is calculated as:

$$CO_{2}e_{Stored} = F_{B} \times \sum_{i}^{N} CO_{2}e_{Storage,i}$$

(Equation 2)

• $F_{B}$ is the biogenic fraction that is eligible for Crediting. If all captured $CO_{2}$ is biogenic, $F_{B} = 1$. Otherwise, see Section 8.2.1.1.
• $CO_{2}e_{Storage,i}$ is the total amount of $CO_{2}$ sequestered in a durable storage reservoir, i, following an applicable storage Module, over the Reporting Period, RP, in tonnes $CO_{2}e$. This term must be measured following the requirements in the respective storage Module.
• $N$ is the total number of durable storage reservoirs used for storage of captured $CO_{2}$.

Quantification of $CO_{2}e_{Storage}$, measurements, and monitoring requirements for the different conversion and storage options are detailed within the respective Modules.

Projects that capture CO₂ that is not entirely of biogenic origin must determine the biogenic fraction that is eligible for Crediting ($F_{B}$). If all captured CO₂ is biogenic, $F_{B}$ = 1.

Projects which use waste feedstocks which contain inseparable biogenic and fossil carbon must use Method A to determine $F_{B}$. The use of Method B may be permitted in certain instances, on a case-by-case basis in agreement with Isometric.

Projects which use biogenic feedstocks co-fired with fossil fuels may use Method A or B to determine $F_{B}$.

Once $F_{B}$ is determined in accordance with Section 8.2.1.1.1 or Section 8.2.1.1.2, the $CO_{2}e_{Storage}$ as determined by the appropriate storage Module(s) must be converted to eligible biogenic $CO_{2}e_{Storage}$ using Equation 2.

$F_{B}$ must be determined by

• Flue sampling location according to ISO 10396/EN 15259 or ASTM D7459.
  • Flue gas sampling may be on the pre-capture or post-capture CO₂ stream.
• Flue sampling according to EN 14181 or ASTM D7459.
• Representative flue gas samples must be taken continuously, integrated over a maximum of a 3 months of operations, by an extractive CEMS.
• Flue gas samples must be demonstrated to be proportionally matched to the flue stack gas mass flow during collection. From these samples, the biogenic fraction ($F_{B}$) must be determined by radiocarbon sampling and determination using ISO 13833:2013 or ASTM D6866-21.

$F_{B}$ must be conservatively determined using a carbon mass balance approach detailed by Equation 3.

$$F_B = \frac{\sum_{i}^{N_B}(m_{Biomass,i} \cdot C_{Biomass,i})}{\sum_{i}^{N_B}(m_{Biomass,i} \cdot C_{Biomass,i}) + \sum_{i}^{N_{FF}}(m_{FF,i} \cdot C_{FF,i})}$$

(Equation 3)

where

• $m_{Biomass,i}$ is the measured dry mass of biomass feedstock, i, used by the Project within a Reporting Period.
• $C_{Biomass,i}$ is the CO₂e of biomass feedstock, i.
• $N_B$ is the total number of biomass feedstocks used in a Reporting Period.
• $m_{FF,i}$ is the measured mass of fossil fuel, i, used by the Project within a Reporting Period.
• $C_{FF,i}$ is the CO₂e of fossil fuel, i.
• $N_{FF}$ is the total number of fossil fuel feedstocks used in a Reporting Period.

For Validation, all projects must estimate an average $F_{B}$ based on:

• Existing or historical data of the mixed biogenic/fossil feedstock or flue gas, localised for the geographic area the Project is situated
• Available calculation factors from the feedstock supplier
• Feedstock sampling and selective dissolution, or
• Literature data

The estimated $F_{B}$ must be included in the PDD, and may be expressed as a monthly profile to account for seasonal variation, or on a per-feedstock basis if the feedstock has low variability.

Type: Counterfactual

As outlined in Section 7.2, refer to both the Biomass Feedstock Accounting Module v1.3 and the relevant storage module for calculation of counterfactual storage.

Type: Emissions

$CO_2e_{Emissions,\ RP}$ is is the total quantity of GHG emissions associated with the Reporting Period, $RP$. This can be calculated as:

$${CO}_{2}^{}e_{Emissions,\ RP}^{}\ = \ {CO}_{2}^{}e_{Establishment,\ RP}^{}\ + \ {CO}_{2}^{}e_{Operations,\ RP}^{} + \ {CO}_{2}^{}e_{End-of-Life,\ RP}^{}+ \ {CO}_{2}^{}e_{Leakage,\ RP}^{}$$

(Equation 4)

Where:

• $CO_2e_{Emissions,\ RP}$ = the total GHG emissions for a Reporting Period, $RP$, in tonnes of CO₂e.
• $CO_2e_{Establishment,\ RP}$ = the total GHG emissions associated with project establishment, for the Reporting Period, $RP$, in tonnes of CO₂e, see Section 8.2.3.1.
• $CO_2e_{Operations,\ RP}$ = the total GHG emissions associated with operational processes for the $RP$, in tonnes of CO₂e, see Section 8.2.3.2.
• $CO_2e_{End-of-Life,\ RP}$ = the total GHG emissions that occur after the $RP$ and are allocated to the $RP$, in tonnes of CO₂e, see Section 8.2.3.3.
• $CO_2e_{Leakage,\ RP}$ = the GHG emissions associated with the Project’s impact on activities that fall outside of the system boundary of a Project, over a given $RP$, in tonnes of CO₂e, see Section 8.2.3.4.

The following sections provide an overview for each variable. Section 8.2.4 provides guidance on specific quantification requirements for activities included in each variable.

GHG emissions associated with $CO_{2}e_{Establishment,\ RP}$ should include all historic emissions incurred as a result of project establishment, including but not limited to the SSRs set out in Table 1.

Project establishment emissions occur from the point of project inception through to before the first removal activity takes place. GHG emissions associated with project establishment may be amortized over the anticipated project lifetime, or per output of product. Rules on amortization are outlined in Section 7 of the GHG Accounting Module.

GHG emissions associated with $CO_2e_{Operations,\ RP}$ must include all emissions associated with operational activities, including but not limited to the SSRs set out in Table 1. This includes all direct emissions as laid out in Section 8.2.3.2.1.

$CO_2e_{Operations,\ RP}$ emissions occur over the Reporting Period for the deployment being Credited and are applicable to the current deployment only. $CO_2e_{Operations\ RP}$ emissions must be attributed to the Reporting Period in which they occur. Allocation of emissions to different Reporting Periods or injection batches may be permitted in certain instances, on a case by case basis in agreement with Isometric.

Bio-CCS processes can generate direct emissions of non-biogenic CO₂ and/or other GHGs due to:

• process leaks
• fugitive emissions
• releases
• GHG-containing tailgas from:
  • conversion processes
  • degradation of sorbents or solvents

Direct emissions reported under this section include non-biogenic CO₂ and other GHGs. Biogenic CO₂ released is reflected in reductions to the measured value of stored CO₂ ($CO_{2eStored,RP}$), which determines net CO₂e removal and crediting.

Additionally, Projects that comply with EC1 in the GHG Accounting Module v1.0, or EC1 in Table 2 may exclude direct emissions, provided these emissions were occuring and would continue to occur in the baseline scenario. This means direct emissions from additional feedstock sourced because of the CDR Project must be accounted for.

All GHGs within the system boundary emitted to the atmosphere must be accurately measured and reported.

All fossil emissions that are not captured by a Project’s capture process must be appropriately quantified. If within the system boundary, they must be reported as $CO_{2}e_{Direct\ Emissions,RP}$ using the following calculation:

$CO_{2}e_{Direct\ Emissions,RP} = \sum_{n=1}^{nv} \sum_{i=1}^{N} V_{i} \cdot W_{n,i} \cdot GWP_{n} \cdot \Delta t_{i}$

(Equation 5)

Where:

• $CO_{2}e_{Direct\ Emissions,RP}$ = The total quantity of GHG emissions associated with the release of flue gas directly into the atmosphere, for a Reporting Period, in tonnes of $CO_{2}e$.
• $nv$ = The total number of GHG species in the emitted flue gas.
• $N$ = The total number of time periods, $i$, within a Reporting Period, RP.
• $V_{i}$ = The total mass flow of all gas over time period $i$, in tonnes per hour.
• $W_{n,i}$ = The concentration of GHG species $n$ within the flue gas, emitted over period $i$, expressed as a mass fraction.
• $GWP_{n}$ = The $GWP_{100}$ for GHG species $n$.
• $\Delta t_{i}$ = The duration of period $i$, in hours.

For combustion process facilities for the provision of power or heat, measurements must be acquired in line with EN 14181 in addition to the requirements below:

• GHG emission concentrations being emitted from the flue stack must be measured by CEMS according to the appropriate international standard, at least once every minute.
• GHG flow rates being emitted from the flue stack must be measured in line with ISO 16911 or similar, at least once every minute.
• CEMS must have a minimum resolution of 2% full scale for both gas concentrations and flow rate.
• CEMS must be positioned in line with EN 15259 or ASTM D7459 to ensure the heterogeneity of the flue gas is appropriately represented.
• CEMS must be calibrated to the manufacturer standards at least once a year or as specified by the manufacturer, whichever is more frequent.
• All raw data, including calibration values, must be made available on request.

For all other Projects:

• The total quantity of direct emissions can be measured by various acceptable methods, including:
  • Use of calibrated flow meters to provide continuous volumetric or mass flow measurement of a release from a process. Any flow meter must be calibrated for the composition and density of tail gas,¹⁴ or use appropriate conversion factors;
  • Use of flow data and curves from tail gas emissions testing and pressure drop measurement (i.e. pitot tubes) in the tail gas stream. Such testing data should be produced by a qualified emissions testing company, accredited to the Stack Testing Accreditation Council for ASTM D7036, ISO 17025, or approved by the authority of the geography where the Project is located or the most stringent of relevant standards worldwide. Testing should be completed under representative process operating conditions;
  • Calculation of tail gas amount by a carbon material balance calculated based on direct measurement of other process streams;
  • Measurement of a storage vessel pressure and temperature at beginning and end of a defined period within the Reporting Period, $RP$;
    • Calculation of total mass of gas can be completed based on gas composition data and temperature and pressure data to determine if release has occurred;
  • Weight of a storage vessel as determined by calibrated weigh scale or load sensor at beginning and end of a defined period within the Reporting Period, $RP$.
• The concentration of GHGs in direct emissions must be measured directly via one of the following methods:
  • On-line analyzer measurement of GHG concentration, such as on-line gas chromatography, non-dispersive infrared (NDIR) detector, or similar. Analyzers must be calibrated regularly using NIST-traceable certified gas standards with concentrations of GHGs within +/- 30% of expected average tail gas concentration;^15,16
  • Use of concentration data from process stream tail gas emissions testing. Such testing data should be produced by a qualified emissions testing company, accredited to the Stack Testing Accreditation Council for ASTM D7036, ISO 17025, or approved by the authority of the geography where the Project is located or the most stringent of relevant standards worldwide. Emissions data should only be used when process operating conditions during Reporting Period are similar to the conditions under which testing was completed;
  • Measurement of stream composition by approved test methods, including national and international standards, such as NIST, ASTM, or other, which target the GHG of concern and are completed by a qualified laboratory;
    • analyses must be completed at least quarterly.

In the event of a process malfunction (such as mechanical failure, gas leaks and/or PRV actuation events), direct measurement will sometimes not be possible and direct emissions through these routes must need to be documented and reported in the Reporting Period in which they occur, with best possible conservative estimations of emissions, in agreement with Isometric.

The Project Proponent must maintain the following records as evidence supporting calculation of direct emissions:

• All raw data and data processing or calculation records for measurements and calculations of emissions;
• Results of any emissions tests used to determine emission rates of GHGs from process streams or flow measurements of gas flow from Bio-CCS or related processes, including signed report from accredited emissions testing entity;
• Flow rate data from flow meters (including pitot tubes) for each period of interest, including flow meter data recorded in data acquisition systems, manual operation logs, or other records indicating date, time, and flow rate, as well as meter identification number or ID;
• Documentation of any known evidence of releases, such as:
  • Pressure relief valve activation (open/close position, or safety valve failure and replacement record);
  • Observed change in weight of storage vessels, and
  • Visual observation of release records with followup measurements and documentation of release.

Records of all data and analyses must be maintained by the Project Proponent and provided for verification purposes for a period of five years.

In order to conservatively determine the fossil CO₂ emitted due to the Project between capture and storage, the quantity of fossil CO₂ captured must be quantified and the quantity of fossil CO₂ proven to be durably stored by the Project must be deducted.

Projects which use waste feedstocks which contain inseparable biogenic and fossil carbon must use Method A to determine the direct emissions .

Projects which use biogenic feedstocks co-fired with fossil fuels may use Method A or B to determine the fossil.

$$CO_{2}e{_{{Post-Capture\text{ }Emissions}}} = CO_{2}e{_{Captured}} \cdot (1-F_B) - \left(\sum CO_{2}e{_{Storage}} \cdot (1-F_B)\right)$$

(Equation 6)

Where:

• $CO_{2}e{_{Post-Capture\text{ }Emissions}}$ is the total GHG emissions between capture and storage for a Reporting Period, RP, in tonnes of CO₂e.
• $CO_{2}e_{{Captured}}$ is the mass of CO₂ measured at the point of capture, according to Section 8.2.3.2.6.
• $F_{B}$ is the biogenic fraction that is eligible for Crediting. If all captured $CO_{2}$ is biogenic, $F_{B} = 1$. See Section 8.2.1.1.

$CO_2e_{{Captured, RP}}$ represents the gross amount of CO₂ captured by the Project during a Reporting Period.

This can be calculated by using the mass and average concentration of CO₂ over a given time period, summed across the whole $RP$:

$$CO_2e_{Captured,\ RP} = \sum_{t=1}^{T}  C_{mean,cap,t} \cdot m_{cap,t}$$

(Equation 7)

Where:

• $C_{mean,cap,t}$ = the measured average concentration as weight percent (%wt) of CO₂ within the captured fluid, or measured C content divided by the fraction of C in CO₂ for dissolved CO₂.
• $m_{cap,t}$ = the mass of CO₂-containing fluid captured during period $t$.
• $t$ = the time index, ranging from 1 to $T$.
• $T$ = $RP/Δt$, the number of time units in the Reporting Period, $RP$.
• $Δt$ = the time interval the average is taken over.

The mass of CO₂-containing fluid captured, $m_{cap,t}$, may either be directly measured using a mass flow meter, or may be indirectly measured by combining suitable volume and density measurements. In the latter case, the mass is calculated as:

$$m_{cap,t} = V_{cap,t} \cdot \rho_{cap,t}$$

(Equation 8)

Where:

• $V_{cap,t}$ = the volume of CO₂-containing fluid captured during period $t$.
• $\rho_{cap,t}$ = the density of CO₂-containing fluid captured during period $t$.

The density of the fluid captured may be measured either using a calibrated density meter, or may be indirectly measured by combining suitable pressure and temperature measurements. In the latter case, the density should be determined as a function of the pressure and temperature measurements by application of a suitable gas-phase equation of state model. Supporting information, including appropriate published scientific literature and/or internal empirical evidence, demonstrating the accuracy of the applied equation of state must be provided at the point of project verification.

The concentration of CO₂ in the captured fluid stream must be:

• Measured after the capture process and before the fluid leaves the capture facility or is mixed with other CO₂ streams. and
• Measured using a continuous inline analyzer for CO₂ concentration, such as NDIR, TDL, or similar, which satisfies the below requirements:
  • Must have an accuracy of 2% of full scale or better;
  • Recorded at a frequency of 1-minute intervals at minimum;
  • Must be calibrated in accordance with and at a frequency which meets or exceeds manufacturer calibration requirements, but which in any case must be no less than annual;
  • Calibration gasses must be traceable to national standards and a certificate of analysis indicating so; and
  • Raw data must be made available upon request.

The mass of captured fluid ($m_{cap}$) is measured via use of a calibrated mass flow meter or volumetric flow meter and density measurements over a defined time interval (Δt). Preference is for high-accuracy flow meters such as coriolis or thermal mass flow meters, although other metering solutions are allowable. Flow metering must meet the following requirements:

• Provided with a factory calibration for the specific gas composition range expected;
• Meter accuracy specification of 2% full scale;
• Must be calibrated in accordance with and at a frequency which meets or exceeds manufacturer calibration requirements, but which in any case must be no less than annual;
• Calibration traceable to national standards;
• Meters are selected and installed for the expected and observed operating range of the captured fluid;
• Meters are installed in accordance with manufacture installation guidelines, including, for example, minimum distances up or downstream of piping disturbances required to ensure accurate flow measurement; and
• Raw data must be made available upon request

Alternative methods of measuring the mass of CO₂ captured on a batch basis in agreement with Isometric.

$$CO_{2}e_{{Post-Capture\text{ }Emissions}} = \sum_{i}^{N_{FF}}(m_{FF} \cdot C_{FF}) - \left(\sum_{j}^{N} CO_{2}e_{{Storage,j}} \cdot (1-F_B)\right)$$

(Equation 9)

Where:

• $CO_{2}e{_{{Post-Capture\text{ }Emissions}}}$ is the total GHG emissions between capture and storage for a Reporting Period, RP, in tonnes of CO₂e.
• $m_{FF,i}$ is the measured mass of fossil fuel, i, used by the Project within a Reporting Period.
• $C_{FF,i}$ is the CO₂e of fossil fuel, i.
• $N_{FF}$ is the total number of fossil fuel feedstocks used in a Reporting Period.
• $F_{B}$ is the biogenic fraction that is eligible for Crediting. If all captured $CO_{2}$ is biogenic, $F_{B} = 1$. Otherwise, see Section 8.2.1.1.
• $CO_{2}e_{Storage,j}$ is the total amount of $CO_{2}$ sequestered in a durable storage reservoir, j, following an applicable storage Module, over the Reporting Period, RP, in tonnes $CO_{2}e$. This term must be measured following the requirements in the respective storage Module.
• $N$ is the total number of durable storage reservoirs used for storage of captured $CO_{2}$.

$CO_2e_{End-of-Life,\ RP}$ includes all emissions associated with activities that are anticipated to occur after the Reporting Period, but are directly or indirectly related to the Reporting Period. For example, this could include ongoing sampling activities for MRV for the specific deployment (directly related), or end-of-life emissions for the Project facility (indirectly related to all deployments).

GHG emissions associated with $CO_2e_{End-of-Life,\ RP}$ may occur from the end of the Reporting Period onward, and typically through to completion of project site deconstruction and any other end-of-life activities.

GHG emissions associated with activities that are directly related to each deployment must be quantified as part of that Reporting Period. GHG emissions associated with activities that are indirectly related to all deployments may be allocated in the same ways as set out in $CO_2e_{Establishment,\ RP}$.

Given the uncertain nature of $CO_2e_{End-of-Life,\ RP}$ emissions, assumptions must be revisited at each Crediting Period and any necessary adjustments made. Furthermore, if there are unexpected $CO_2e_{End-of-Life,\ RP}$ emissions associated with a Reporting Period, or the Project as a whole, that occur after the Project has ended, then the reversal process will be triggered to compensate for any emissions not accounted for.

$CO_2e_{Leakage,\ RP}$ includes emissions associated with a project's impact on activities that fall outside of the system boundary of a Project.

It includes increases in GHG emissions as a result of the Project displacing emissions or causing a knock on effect that increases emissions elsewhere. This includes emissions associated with activity-shifting, market leakage and ecological leakage.

It is the Project Proponent's responsibility to identify potential sources of leakage emissions. As a minimum Bio-CCS projects must account for market leakage emissions in accordance with the Biomass Feedstock Accounting Module v1.3 and the relevant storage modules, as well as energy leakage associated with reductions in efficiency of wider processes, or reduction in energy outputs as a result of the CDR Project.

$CO_2e_{Leakage,\ RP}$ emissions must be attributed to the Reporting Period in which they occur. Allocation may be permitted in certain instances, on a case-by-case basis in agreement with Isometric.

The Project Proponent must identify, highlight and justify any data gaps and missing calibration data should they occur. Isometric and the VVB must be notified of data gaps and missing calibration data as soon as they become evident. Documentation that explains the approach taken and details the missing data must be provided to Isometric and the VVB and included in the GHG Statement.

For parameters that require sub-hourly measurements (such as direct GHG emission concentrations and flow rates), the Project Proponent must adhere to the following procedure for handling missing data events.

Where data gaps in measurements are 30 minutes or less in duration, the Project Proponent must use an average measurement utilising measurements taken 30 minutes prior to and following the data gap.

Where data gaps in measurements are longer than 30 minutes in duration, the Project Proponent must apply the above approach for up to a 30 minute period within the duration of the data gap only. For the remaining duration of the data gap the Project Proponent must assume a conservative stance in consultation with Isometric, depending on the nature of the data loss as detailed below:

• If the data loss pertains to the capture of biogenic CO₂, no carbon dioxide removal can be claimed due to the lack of data.
• If the data loss pertains to GHG emissions, for example, from the flue stack to the atmosphere, the Project Proponent must assume a maximum value for the release of GHG emissions identified from the 24 hours prior to, and the 24 hours following the data gap.
• If the data loss pertains to $F_{B}$, the Project Proponent may justify the use of an averaged $F_{B}$ based on comparable historic data for the feedstock type and time period. This justification will require evidence of low variability in $F_{B}$ over comparable periods to the data gap, and must be a conservative estimation by subtracting the standard deviation of the averaged or historical data.

In addition, data gaps must account for less than 5% of the data used for both the calculation of removals and the calculation of emissions within a given Reporting Period, any data missing above this threshold will also be subject to the conservative rules outlined above.

Where calibrations are missed, one must be completed as soon as this becomes evident. For data collected between when the calibration was required and when it took place, a conservative estimate should be agreed between the VVB, Project Proponent and Isometric.

GHG emissions accounting must be undertaken in alignment with the GHG Accounting Module v1.0, which ensures a consistently rigorous standard in how GHG emissions are quantified and reported between different CDR Projects and approaches. This includes:

• Requirements for data quality, including a detailed data quality hierarchy for activity data and emission factors;
• Consideration of Materiality in emissions accounting;
• Emissions amortization requirements; and
• By-product accounting relating to inputs to the process that are by-products.

Embodied emissions associated with system inputs considered to be waste products can be excluded from the accounting of the GHG Statement system boundary provided the appropriate eligibility criteria are met.

For waste energy inputs, for example the use of waste heat, refer to the Energy Use Accounting Module v1.3.

All biomass feedstock must be eligible and accounted for according to the Biomass Feedstock Accounting Module v1.3.

For all other waste inputs, refer to Section 6.3 of the GHG Accounting Module v1.0.

The Bio-CCS process may result in the production of co-products, such as electricity and heat. Projects must follow the co-product allocation procedures described in Section 6.1 of the GHG Accounting Module v1.0. This includes provisions for a narrow system boundary in instances where the facility is a retrofit and provisions for applying the substitution method.

In addition to the requirements set out in the GHG Accounting Module v1.0, Bio-CCS projects may follow the additional provisions below for Procedure 2: Dividing the process into sub-processes (as set out in the GHG Accounting Module v1.0) if they comply with EC1 in Table 2.

Table 2. Additional eligibility criteria for dividing the process into sub-processes

For Bio-CCS Projects capturing both fossil and biogenic CO₂, Project emissions ($CO_{2}e_{Emissions}$) by default must be fully allocated to the CDR Project. However, if the Project can satisfy all of Eligibility Criteria EC2 to EC5 in Table 3, they may undertake a mass-balance allocation of emissions to the biogenic fraction.

Table 3. Eligibility criteria for mass balance emissions allocation

If eligible, Projects may allocate Project emissions to the biogenic fraction by multiplying relevant Project emissions by $F_B$ in line with Equation 10. Relevant Project emissions are those where the same processes are shared between fossil and biogenic CO₂ capture and storage. $CO_{2}^{}e_{Leakage}$ emissions must not be allocated.

$${CO}_{2}^{}e_{Emissions,\ RP}^{}\ = \ F_B\ *\ ({CO}_{2}^{}e_{Establishment,\ RP}^{}\ + \ {CO}_{2}^{}e_{Operations,\ RP}^{} + \ {CO}_{2}^{}e_{End-of-Life,\ RP}^{}) \ + \ {CO}_{2}^{}e_{Leakage,\ RP}^{}$$

(Equation 10)

Where

• $CO_2e_{Emissions,\ RP}$ = the total GHG emissions for a Reporting Period, $RP$, in tonnes of CO₂e.
• $F_B$ = is the biogenic fraction that is eligible for Crediting. If all captured CO₂ is biogenic, $F_B$ = 1. See Section 8.2.1.1.
• $CO_2e_{Establishment,\ RP}$ = the total GHG emissions associated with project establishment, for the Reporting Period, $RP$, in tonnes of CO₂e, see Section 8.2.3.1.
• $CO_2e_{Operations,\ RP}$ = the total GHG emissions associated with operational processes for the $RP$, in tonnes of CO₂e, see Section 8.2.3.2.
• $CO_2e_{End-of-Life,\ RP}$ = the total GHG emissions that occur after the $RP$ and are allocated to the $RP$, in tonnes of CO₂e, see Section 8.2.3.3.
• $CO_2e_{Leakage,\ RP}$ = the GHG emissions associated with the Project’s impact on activities that fall outside of the system boundary of a Project, over a given $RP$, in tonnes of CO₂e, see Section 8.2.3.4.

This section sets out specific requirements relating to quantification of energy use as part of the GHG Statement. Emissions associated with energy usage result from the consumption of electricity or fuel.

Examples of electricity usage may include, but are not limited to:

• Capture Process:
  • Electricity used in process operations, including renewable energy, such as:
    • Sorbent/solvent or other regeneration process (electrically heated, electrochemical, or other).
    • Electricity for pumps, motors, drives, etc.
    • Electricity for instrumentation and controls; and
    • Electricity for building operation and management for capture buildings and direct support buildings.
      • Research and development and administrative facilities are not included.
  • Fuel combustion for thermal energy generation (heat/steam) such as:
    • Sorbent/solvent or other regeneration process (thermal); and
    • Heat for capture process buildings and operations.
  • Heat utilization for thermal processes;¹⁷ and
  • Cryogenic processes for CO₂ purification or liquefaction.
• CO₂ Transportation:
  • Electricity or fuel used for operation of a pipeline or similar non-mobile CO₂ transportation process.
• CO₂ Storage:
  • Electricity used for operation of any CO₂ conversion processes, such as ex-situ carbonate production and handling;
  • Electricity used for injection operations, including any pumps, compressors (including for compression into supercritical CO₂), or related equipment inside the injection facility gate; and
  • Fuel used for heat generation or other purposes at the conversion or injection sites.

Process emissions associated with The Project will be calculated by totaling the energy use (thermal and electrical) of all equipment within the project boundary. To determine the energy use, the following measurements must be provided:

Electricity:

• Total electricity use for the CDR process. This may be measured at a single metering point that includes all electricity consumption within the CDR process, or at multiple sub-meters that, in total, account for all electricity use by the CDR process;
• Total electricity production for the bioenergy system (gross generation);
• Total electricity exported to the grid or customers.

When the electricity is provided to the CCS processes via the output of a Bio-CCS facility which produces electricity, the cradle-to-grave emissions factor for the bioenergy facility shall be used as the primary emissions factor for calculation of electricity related emissions for the CDR process.

Electricity metering and record keeping must be performed in accordance with the Energy Use Accounting Module v1.3.

Thermal Energy

Any thermal energy used by the CDR process must be monitored, including steam use, direct combustion of fuels within the CDR process to provide heat, and use of waste heat.

In the case of steam, waste heat, or other thermal inputs to the CDR Process, measurements must be made of the total thermal energy supplied to the CDR Process. Total thermal energy must be measured using the following methods:

• Mass flow meter (coriolis, multivariable vortex meter, or similar) calibrated for steam measurement with accuracy specification of +/- 2% of reading or better on supply or return;
• Volumetric flow meter (differential pressure, turbine, or other) in conjunction with temperature and pressure measurement using calibrated instrumentation, providing a combined accuracy of total steam flow of +/- 2% or better on supply or return;
• Temperature and pressure measurement on both supply and return;
• Specifications of gas or thermal fluid (i.e. heat transfer fluid), including density and specific heat.

Emissions associated with thermal energy and its production, and record keeping, must be performed in accordance with the Energy Use Accounting Module v1.3.

The Energy Use Accounting Module v1.3 provides requirements on how energy-related emissions must be calculated so that they can be subtracted in the net CO₂e removal calculation. It sets out the calculation approach to be followed for intensive facilities and non-intensive facilities and acceptable emissions factors.

This section sets out specific requirements relating to quantification of emissions related to transportation.

Emissions associated with transportation should include transportation of products as part of a batch $n$’s process, including the following:

• Transport of biomass feedstock;
• Transport of compressed gaseous or liquid CO₂ or CO₂ containing fluid or carbonated minerals;
• Transport and shipping related to collection and analysis of samples for environmental monitoring or lab analysis.

Section 4.2 of the GHG Accounting Module v1.0 provides requirements on how transportation-related emissions must be calculated so that they can be subtracted in the net CO₂e removal calculation. It sets out the calculation scope, approach to be followed, and acceptable emissions factors.

This section sets out specific requirements relating to quantification of embodied emissions as part of the GHG Statement. Embodied emissions are those related to the life cycle impact of equipment and consumables.

The Project Proponent must identify all equipment and consumables used in the biomass conversion and storage process, identify appropriate cradle to grave emission factors, and allocate the emissions to removals appropriately.

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

• Equipment, including:

  • Equipment and infrastructure for processes relating to the wider facility, for example energy generation or product manufacturing.

  • CO₂ capture process:

    • Process equipment, including process units for capture and sorbent regeneration;
    • Sorbent, solvent, or other material handling systems, such as pumps, conveyors, augers, feed bins, and related equipment;
    • Heat transfer equipment;
    • CO₂ purification equipment;
    • CO₂ compression and storage equipment (on-site); and
    • Preparation or mixing equipment for sorbents, solvents, or other materials.

  • CO₂ transportation:

    • Equipment used for transportation of CO₂, including pipelines, and any pumps or compressors.

  • CO₂ storage:

    • Ex-situ CO₂ conversion or reaction equipment (i.e. for carbonate production), including all vessels, pumps, storage, and other process equipment;
    • Closed-system temporary holding of CO₂ at the injection site; and
    • CO₂ injection equipment, including compressors, pumps, and all wellbore equipment and materials.

  • Monitoring:

    • Monitoring wells and all associated materials (steel casing, concrete, etc.);
    • On-line analyzers, measurement equipment, or other such devices; and
    • Buildings and associated equipment utilized for monitoring purposes(e.g., on-site laboratories).

  • Universal equipment for all processes:

    • Pumps, piping, and related equipment;
    • Storage tanks;
    • All support structures, facilities, and infrastructure, including steel platforms, framing, supports, concrete footings, building structures, offshore rigs where applicable etc.; and
    • All instrumentation, controls, and other process management equipment.

• Consumables, including:

  • Consumables for processes relating to the wider facility, for example energy generation or product manufacturing.

  • Capture Process:

    • Sorbents or solvents, including emissions associated with:
      • Sorbent production including any CO₂ emissions released directly from sorbent production, such as emissions of CO₂ from calcination of limestone; and
      • Proper disposal of used sorbents
    • Heat transfer fluids such as thermal oils or refrigerants.

  • CO₂ storage:

    • Feedstocks or reactants used in the conversion of CO₂ to other products for storage; and
    • dilutants or additives used to support or improve injection of CO₂ or CO₂-containing product.

  • Monitoring:

    • Gases, reagents, or other materials used for operation of monitoring equipment, analytical testing, calibration of monitoring equipment and on-site analyzers; and
    • Consumable sampling equipment or supplies that are used in significant quantities.

  • Universal consumables for all processes:

    • Gases such as nitrogen used for process operations, instrumentation, purges, or other operations;
    • Water, including full cradle-to-grave emissions associated with:
      • Delivery of process water (including cooling water), including embodied emissions associated with water production equipment, such as new wellbores, pumps, and piping, and all energy usage for delivery.
      • Disposal or treatment of used or waste process water (including cooling water), including emissions associated with wastewater treatment.
    • Water treatment chemicals used in cooling or process water.

Section 4.1 of the GHG Accounting Module v1.0 sets out the calculation approach to be followed including allocation of embodied emissions, life cycle stages to be considered, data sources and emission factors.

This Protocol provides multiple options for conversion and durable storage of CO₂. The Project Proponent can choose from available options when submitting their Project for verification:

Isometric would like to thank following contributors to previous versions this Protocol and relevant Modules:

• Tim Hansen (350 Solutions); Biogenic Carbon Capture and Storage Protocol and Energy Use Accounting Modules.
• Danny Cullenward (University of Pennsylvania); Biogenic Carbon Capture and Storage Protocol and Biomass Feedstock Accounting Module.
• Kevin Fingerman (California State Polytechnic University-- Humboldt); Biogenic Carbon Capture and Storage Protocol and Biomass Feedstock Accounting Module.
• Chris Holdsworth (University of Edinburgh); CO₂ Storage in Saline Aquifers and CO₂ Storage via In-Situ Mineralization in Mafic and Ultramafic Formations Modules.
• Wilson Ricks (Princeton University); Energy Use Accounting Module.

This section provides guidance for Projects which capture fossil CO₂, whether through mixed feedstocks or co-firing with fossil fuels.

Note that for the purposes of this Protocol, geologic CO₂ liberated from minerals is considered fossil CO₂ unless it can be demonstrated that the CO₂ is of biogenic origin and mineralized by the Project (for example, as a sorbent).

For CO₂ leaks prior to the point of quantification of $CO_{2}e_{Storage}$(according to the storage Module), for eligible biogenic CO₂ there is no penalty for emitting CO₂, as in the counterfactual scenario this CO₂ would have entered the atmosphere.

However, whether emitted fossil CO₂ is considered within the system boundary is dependent on The Project type:

• For retrofit projects where the fossil emissions are present in the baseline scenario, these emissions are not considered an emissions source.
• For retrofit projects where the use of fossil fuels (or waste feedstocks where biogenic and fossil carbon is inseparable) is above the baseline usage rate (see Appendix B: Baselines, these emissions must be accounted for according to Section 8.2.3.2, as these emissions of fossil CO₂ to the atmosphere would not have occurred in the absence of the Project.
• For all other Projects, fossil direct emissions and leaks must be accounted for according to Section 8.2.3.

Once fossil CO₂ is durably stored by the Project, any emission of CO₂ from the storage reservoir attributable to the Project is considered a reversal, regardless of $F_{B}$, excluding fossil CO₂ that can be robustly demonstrated to be part of the baseline scenario (see Appendix B: Baselines), in agreement with Isometric and the VVB.

For quantification of the fossil component of any mixed CO₂ emission from the Project, use Equation A1.

$$CO_{2}e_{{Misc, Fossil}} = (1-F_B) \cdot CO_{2}e_{Misc}$$

(Equation A1)

Where

• $CO_{2}e$ is the total amount of CO₂e, in tonnes.

For guidance on the construction of a baseline for a Project that is drawing a narrow system boundary, see Appendix D of the Biomass Feedstock Accounting Module v1.3. The concept of Baseline Feedstock Consumption rate can be applied to drawing a baseline fossil fuel usage. Usage of fossil fuels above this rate must be within the system boundary.

Factors that characterize a robust cap-and-trade policy include:

• emission limits that are stringent in relation to emissions, inclusive of any banked compliance instruments,
• effective border adjustment policies that minimize carbon leakage, especially in the electricity sector,
• the legal authority and apparent political commitment to operate the market over long time horizons, and
• any other major factors that illustrate a high likelihood of credible, binding emission limits for covered facilities.

Currently the EU Emissions Trading Scheme, which covers the 27 EU member nations as well as Iceland, Norway, and Liechtenstein; and the UK Emissions Trading Scheme are the only cap-and-trade jurisdiction approved as sufficiently rigorous under this Protocol.

This risk assessment identifies the pathway specific risk factors relevant to a carbon removal project. The relevant risk factors identified as part of a risk assessment are included in the monitoring plan requirements for the Project, with details included in the Project Design Document. Project specific risk factors inform the required duration of monitoring along with the monitoring requirements set out in the Protocol and the requirements set out in the Monitoring Section of the Isometric Standard.

The risk score, as determined by the Risk of Reversal Questionnaire, will determine a project’s buffer pool contribution. Projects must re-assess their reversal risk at the renewal of each crediting period, or if monitoring identifies a reversal-related risk, or if an actual reversal event takes place. In any event, projects should reassess their reversal risk at a minimum every 5 years.

The Risk of Reversal Questionnaire questions that pertain to this Protocol, drawn from the programme-level Risk of Reversal Questionnaire defined in Appendix B: Risk Reversal Questionnaire of the Isometric Standard, include the following:

Risk Score Categories

• 0: Very Low Risk Level (2% buffer)
• 1-2: Low Risk Level (5% buffer)
• 3-4: Medium Risk Level (7% buffer)
• 5+: High Risk Level (10-20% buffer)

Project specific risk factors will depend on the form of carbon being stored (i.e., organic vs. inorganic), the method of storage (e.g., mineralization, encapsulation), the location of carbon storage (e.g., subsurface, ocean), and the proximity of that carbon to potential agents of reversal.

For projects with carbon storage as inorganic carbon, the presence the following risk factors must be reflected in the risk score corresponding to question 10:

• Acidic fluid
• Alkaline fluid (if stored as dissolved inorganic carbon)
• Temperatures in excess of 800 degrees celsius

For projects with any form of subsurface carbon storage, the presence of the following risk factors must be reflected in the risk score corresponding to question 10:

• Seismicity
• Subsurface migration

California Air Resources Board. (2022). Carbon Sequestration: Carbon Capture, Removal, Utilization, and Storage. https://ww2.arb.ca.gov/our-work/programs/carbon-sequestration-carbon-capture-removal-utilization-and-storage

Environment and Climate Change Canada. Clean Fuel Regulations: Quantification Method for CO₂ Capture and Permanent Storage Version 1.0. (2022) https://publications.gc.ca/collections/collection_2022/eccc/En4-474-2022-eng.pdf

Intergovernmental Panel on Climate Change. (2005). IPCC Special Report on CO₂ Capture and Storage https://www.ipcc.ch/site/assets/uploads/2018/03/srccs_wholereport-1.pdf

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. (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. (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 s 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

International Organization for Standardization. (2022). ISO 9300:2022 Measurement of gas flow by means of critical flow nozzles. https://www.iso.org/standard/77401.html

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1. Shi, X., Xiao, H., Azarabadi, H., Song, J., Wu, X., Chen, X., and Lackner, K. S. (2020). Sorbents for the Direct Capture of CO₂ from Ambient Air. Angewandte Chemie International Edition, 59, 6984–7006. https://doi.org/10.1002/anie.201906756 ↩

2. Custelcean, R. (2022). Direct Air Capture of CO₂ Using Solvents. Annual Review of Chemical and Biomolecular Engineering, 13, 217–234. https://doi.org/10.1146/annurev-chembioeng-092120-023936 ↩

3. Fujikawa, S., and Selyanchyn, R. (2022). Direct air capture by membranes. MRS Bulletin, 47, 416–423. https://doi.org/10.1557/s43577-022-00313-6 ↩

4. Renfrew, S. E., Starr, D. E., and Strasser, P. (2020). Electrochemical Approaches toward CO₂ Capture and Concentration. ACS Catalysis, 10, 13058–13074. https://doi.org/10.1021/acscatal.0c03639 ↩

5. Al Hameli, F., Belhaj, H., and Al Dhuhoori, M. (2022). CO₂ Sequestration Overview in Geological Formations: Trapping Mechanisms Matrix Assessment. Energies, 15, Article 20. https://doi.org/10.3390/en15207805 ↩

6. Rochelle, C. A., Czernichowski-Lauriol, I., and Milodowski, A. E. (2004). The impact of chemical reactions on CO₂ storage in geological formations: A brief review. Geological Society, London, Special Publications, 233, 87–106. https://doi.org/10.1144/GSL.SP.2004.233.01.07 ↩

7. Terlouw, T., Treyer, K., Bauer, C., and Mazzotti, M. (2021). Life Cycle Assessment of Direct Air Carbon Capture and Storage with Low-Carbon Energy Sources. Environmental Science & Technology, 55, 11397–11411. https://doi.org/10.1021/acs.est.1c03263 ↩

8. Ricks, W., Xu, Q., and Jenkins, J. D. (2023). Minimizing emissions from grid-based hydrogen production in the United States. Environmental Research Letters, 18, 014025. https://doi.org/10.1088/1748-9326/acacb5 ↩

9. Erans, M., Sanz-Pérez, E. S., Hanak, D. P., Clulow, Z., Reiner, D. M., and Mutch, G. A. (2022). Direct air capture: Process technology, techno-economic and socio-political challenges. Energy & Environmental Science, 15, 1360–1405. https://doi.org/10.1039/D1EE03523A ↩

10. For example, 49 CFR §195.402 - Transportation of Hazardous Liquids via Pipeline: Procedural manual for operations, maintenance, and emergencies, and 40 CFR §146.94 - Class VI Wells: Emergency and remedial response. ↩ ↩²

11. Water neutrality is defined as: the total demand for water should be the same after new development is built, as it was before. That is, the new demand for water should be offset in the existing community by making existing infrastructure and homes in the area more water efficient. ↩

12. ISO 14064-3: 2019, Section 5.1.7 ↩

13. Carbon Credit Quality Initiative. Methodology for assessing the quality of carbon credits, Version 3.0 (May 2022). https://carboncreditquality.org/methodology.html ↩

14. Flow meters must be calibrated to national traceable standards by an ISO 17025 accredited metrology laboratory. Flow meters may include critical nozzle flow meters (i.e. ISO 9300:2022 compliant meters), coriolis mass flow meters, and other applicable meters for mixed gas flows, as long as properly calibrated and maintained. ↩

15. Dinh, T.-V., Choi, I.-Y., Son, Y.-S., and Kim, J.-C. (2016). A review on non-dispersive infrared gas sensors: Improvement of sensor detection limit and interference correction. Sensors and Actuators B: Chemical, 231, 529–538. https://doi.org/10.1016/j.snb.2016.03.040 ↩

16. Sandoval-Bohorquez, V. S., Rozo, E. A. V., and Baldovino-Medrano, V. G. (2020). A method for the highly accurate quantification of gas streams by on-line chromatography. Journal of Chromatography A, 1626, 461355. https://doi.org/10.1016/j.chroma.2020.461355 ↩

17. Lyons, L., Kavvadias, K. and Carlsson, J., (2021). Defining and accounting for waste heat and cold. EUR 30869 EN, Publications Office of the European Union, Luxembourg. doi:10.2760/73253. https://publications.jrc.ec.europa.eu/repository/handle/JRC126383 ↩