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 (Biogenic CCS). This Protocol is developed for application to Biogenic CCS processes or combinations of processes (e.g., solid sorption¹, liquid solvent², membrane processes³, electrochemistry⁴, etc.) in which a cradle-to-grave GHG Statement can be accurately applied and in which the CO₂ captured is stored with >1000 years durability.

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; and
• 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; and
• 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 Biogenic CCS. As Biogenic CCS is still a developing approach to CO₂ removal (CDR) with ever-expanding published literature, the Protocol incorporates requirements that may be more stringent than some current regulations or other Protocols. The approach taken here may be altered in future versions of the Protocol technology and research advance.

This Protocol applies to projects anywhere that capture point-source biogenic carbon sourced from an eligible biomass feedstock as outlined in the Biomass Feedstock Accounting Module and store this carbon with >1000 years durability via physical or chemical trapping mechanisms laid out in the relevant CO₂ Storage Module. Projects that capture CO₂ that is not of biogenic origin are not eligible. A cradle-to-grave GHG Statement must also be able to be accurately applied to all processes within the scope of the project.

The project must consider environmental and social impacts and the Project Proponent must provide evidence that the project will do no net environmental or social harm by complying with Section 3.7.1 of the Isometric Standard as well as the following requirements:

• CO₂ storage 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 regulations⁵ (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 requirements⁵ and covers the 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 Biogenic 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.
• 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 when it comes to 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 neutrality⁶.

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 Biogenic CCS, for example:

• Documentation of additionality of CCS and non-additionality of co-product production facilities not included in 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 this Protocol, including demonstration of required records.
3. Verify that the Environmental & Social Safeguards 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 as⁷:

• 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 validation and initial verification to the capture and storage site. Validators 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 every 2 years at each location.

Verifiers and validators 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, geological storage of CO₂, electricity procurement and heat/power generation.

Competency must be demonstrated through the below relevant sectoral scope acCreditations, or through demonstration of relevant experience, in accordance with Isometric's VVB policy:

• Storage - Carbon Capture and Storage of CO₂ in Geological Formations

CO₂ removal via Biogenic CCS and subsequent storage 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., injection site operators), and to avoid double counting of CO₂e removals, a single Project Proponent must be specified contractually as the sole owner of the CO₂e removals. 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;
• 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;
  • 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 should make the project ineligible for future Credits⁸.

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 7.2.1) 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 analysis of carbon content and purity of injected CO₂, CO₂-containing injectants or carbonated minerals (for ex-situ mineralisation); 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](/standard# 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.

Biogenic 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 Biogenic 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 $CO_2e_{Removal}$.

GHG emission calculations must include all emissions related to the project activities that occur within the Reporting Period. This includes: (a) any emissions associated with project establishment allocated to the Reporting Period (See Section 7.6.3.1) (b) any emissions that occur within the Reporting Period (See Section 7.6.3.2), (c) any anticipated emissions that would occur after the Reporting Period that have been allocated to the Reporting Period (See Section 7.6.3.3) and (d) leakage emissions that occur outside of the system boundary that are associated with the Reporting Period (See Section 7.6.3.4).

In line with the Isometric Standard, this Protocol requires that Removal Credits are issued ex-post (after net Removal from the atmosphere via Biogenic CCS has been achieved). Credits may be issued once CO₂ has been permanently stored in the identified storage reservoir.

The scope of this Protocol includes GHG sources, sinks and reservoirs (SSRs) associated with a Biogenic CCS CDR 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 as direct emissions from a process or storage system or as indirect emissions from combustion of fuels, electricity generation, or other sources. Emissions for processes within the system boundary must include all GHG SSRs from the construction or manufacturing of any project-specific physical site and associated equipment; closure and disposal of each site and associated equipment; and operation of each process (including feedstock production, transport, spreading and sampling for MRV) to include embodied emissions of consumables in the process.

Any emissions from sub-processes or process changes that would not have taken place without the CDR project, such as subsequent transportation and refining, must be fully considered in the system boundary. Biomass feedstock emissions must be calculated using the as outlined in the Biomass Feedstock Accounting Module. This allows for accurate consideration of additional, incremental emissions induced by the carbon removal process.

The system boundary must include all SSRs controlled by and related to the project, including but not limited to the SSRs 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.

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

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

The Project Proponent must consider all GHGs associated with SSRs, in alignment with the United States Environmental Protection Agency’s definition of GHGs, which includes: 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.

All GHGs must be quantified and converted to CO₂e in the GHG Statement using the 100-yr 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).

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 a project's impact on activities that fall outside of the system boundary of a project must also be considered. This is covered under Leakage in Section 7.6.3.4.

Biogenic CCS facilities will typically have marketable co-products in addition to CO₂ capture. The system boundary of a Biogenic CCS project must include the full system boundary from cradle-to-grave, unless Eigibility Criteria are met which allow a more narrow system boundary to be drawn. Eligibility criteria are set out in Table 2. Projects that meet at least one of the following eligibility criteria may draw a more narrow system boundary which only considers activities related to CCS.

Table 2. Eligibility criteria for allowing a narrow system boundary for a Biogenic CCS project

Regardless of eligibility criteria, emissions associated activities, consumables and equipment related to the CO₂ capture process, CO₂ transportation and CO₂ storage must be included the system boundary. In cases where the Project has demonstrated that the co-product facility is non-additional, universal equipment may be excluded from the system boundary if the Project meets the eligible criteria for a narrow system boundary. However, any implications of the CCS processes that may have led to requirements associated with universal systems, for example additional load bearing capacity, must be proportionally considered within the system boundary.

Any energy use within the system boundary must be accounted for through the requirements set out in the Energy Use Accounting Module. In cases where projects exclude emissions associated with the production of an energy co-product, any reduction in the efficiency of the energy production as a result of the CDR process must be counted towards energy use of the CDR process.

Ancillary activities (such as supplementary research and development activities and corporate administrative activities) that are associated with a project but are not directly or indirectly related to the issuance of Credits can be excluded from the system boundary.

Biogenic 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 Biogenic 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 Biogenic CCS project and the wider facility do not take place and no associated infrastructure is built.
• Retrofit: The baseline scenario assumes that the activities associated with the Biogenic CCS component of the wider facility do not take place and no additional infrastructure associated with CCS is built.

The counterfactual is the CO₂ stored in the biomass feedstock that would have remained durably stored in the biomass feedstock in the absence of the project. This is known as ineligible biomass, given that the CO₂ stored would have remained stored in the biomass in the absence of the CDR project and is therefore not eligible to count towards Crediting. The Biomass Feedstock Accounting Module 1.2 sets out requirements for establishing ineligible biomass as part of the Counterfactual Storage Eligibility criteria. The Biomass Feedstock Accounting Module 1.2 includes details for quantification of $CO_2e_{Counterfactual}$.

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 Biogenic CCS must be calculated as follows for a Reporting Period, $RP$:

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

(Equation 1)

Where;

• $CO_2e_{Removal}$ = the total net CO₂e removed from the atmosphere over a given $RP$, in tonnes CO₂e.
• $CO_2e_{Stored}$ = the total CO₂ removed from the atmosphere and durably stored as biogenic carbon over a given $RP$, in tonnes CO₂e.
• $CO_2e_{Counterfactual}$ = the total CO₂ removed from the atmosphere and durably stored as biogenic carbon in the abscence of the project, over a given $RP$, in tonnes CO₂e.
• $CO_2e_{Emissions}$ = the total GHG emissions associated with the project including leakage, over a given $RP$, in tonnes of CO₂e.

Note: Reversals occur after Credits have been issued so are not included in this equation. See Section 9.2 and Section 5.6 of the Isometric Standard for further information.

Type: Sequestration

$CO_2e_{Stored}$ represents the mass of Carbon (C) as CO₂e present in the CO₂-containing injectant that is injected and stored in the geologic or engineered storage formation in a given $RP$. This is the gross mass stored and does not account for reversals of storage from the storage formation.

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

$$CO_2e_{Stored,\ RP} = \sum_{t=1}^{T}  C_{mean, inj,t} \cdot m_{Inj,t}$$

(Equation 2)

Where:

• $C_{mean,inj,t}$ = the measured concentration as weight percent (%wt) of CO₂ within the injectate, or measured C content divided by the fraction of C in CO₂ for dissolved CO₂ or carbonate solutions
• $m_{Inj,t}$ = the mass of CO₂-containing injectant (in tonnes) injected during $t$
• $t$ = 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

Calculation of $CO_2e_{Stored}$ requires two primary measurements

• concentration of CO₂ or C:
  • ${C_{inj}}$ (%wt of CO₂ in the CO₂ injection stream or %wt C within a carbonate solution divided by C content in CO₂ (44/12), and
  • $m_{Inj}$ (total mass of injectant in tonnes).

The concentration of CO₂ in the gaseous or supercritical CO₂ stream must be:

• measured immediately upstream from the point of injection; and
  • where CO₂ streams from multiple projects are injected into a single storage location, total CO₂ mass input from the project and of the total CO₂ stream to which it is injected may be measured at the location of transfer from the Biogenic CCS facility into the combined stream. The weight fraction of CO₂ determined at this point may be used to calculate the CO₂ injected as measured immediately upstream from the injection point
• measured using a continuous inline analyzer for CO₂ concentration, such as NDIR, TDL, or similar, which satisfies the below requirements:
  • CO₂ analyzer must have an accuracy of 2% of full scale or better, with limited drift specification (<2%)⁹,
  • recorded at a frequency of 1-minute intervals at minimum and output averages at 1-hour intervals at most,
  • must be calibrated in accordance with and at a frequency which meets or exceeds manufacturer calibration requirements, and
    • calibration gases must be traceable to national standards and a certificate of analysis provided indicating so; and
  • raw data must be made available upon request.

If there is a temporary inability to provide continuous measurement and the CO₂ flow is stable, a minimum of three samples must be collected monthly. The C content must then be conservatively estimated by using 1 standard error below the mean for either the Reporting Period or smaller time unit (Δt) set within the PDD.

In these cases the injectate will also be subject to random sampling, to alleviate the risk of any of the stream having a substantially different C content at given time. The random sampling approach must be agreed and documented in the PDD, whereby Isometric will contact the Project Proponent on randomly selected days, at an agreed cadence, which must be no less frequent than once per year, on average. Once contacted, the Project Proponent must sample the CO₂ concentration within 24 hours of being notified. If the Project Proponent is not able to carry out sampling within this timeframe, Project Proponent must provide a justification for why the sampling was not able to be completed, and take the sample as soon as is feasible. If the Project Proponent is unable to carry this random sampling out on 3 occasions, this will trigger a Project review by Isometric with the possibility of project termination.

If premixed dissolved CO₂ is injected into the subsurface or during the ex-situ mineralization processes which may use a carbonate slurry, then the total C content must be determined via the analysis of samples of injectant or input stream, following:

• ASTM D7573-18: Standard Test Method for Total Carbon and Organic Carbon in Water by High Temperature Catalytic Combustion and Infrared Detection; and/or
• ASTM D513-16: Standard Test Methods for Total and Dissolved CO₂ in Water; or
• any other test method for total inorganic carbon or carbonate content developed for the sample matrix of interest, with preference for approved national or international standard test methods.

Carbon content analyses must be completed by an ISO 17025 accredited laboratory, or equivalent, with accreditation including the specific method of interest.

All samples must be collected as individual grab samples from the injectant stream. A minimum of three unique samples must be collected at each time of sampling. Sampling must occur at a minimum quarterly during the year. The C content must then be conservatively estimated by using 1 standard error below the mean for either the Reporting Period or smaller time unit (Δt) set within the PDD. The Project will also be subject to random sampling, to alleviate the risk of substantially different C content measurements at any given time:

• The random sampling approach must be agreed and documented in the Project Design Document, whereby Isometric will contact the Project Proponent on randomly selected days, at an agreed cadence, which must be no less frequent than once per year, on average. Once contacted, the Project Proponent must sample the CO₂ concentration on that day.
• If the Project Proponent is unable to carry this random sampling out on 3 occasions, this will trigger a Project review by Isometric.

Laboratories should complete and provide documentation of standard quality assurance procedures on a schedule in accordance with their quality management plans and acCreditation requirements to include:

• analysis of blanks;
• analysis of duplicates; and
• instrumentation calibrations and analysis of calibration standards.

The mass of injectant ($m_{Inj}$) 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 or injectant composition expected;
• be subject to inspection;
• calibration traceable to national standards;
• manufacturer specifications to which calibration and maintenance are adhered;
• 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;
• meters are selected and installed for the expected and observed operating range of the injection system;
• meter accuracy specification of <2% full scale, with preference for meters with accuracy of 1% or better; and
• metering data recording frequency should be one second intervals at a minimum, however meters may use averaging and provide data outputs on 1-minute to 1-hour averaged frequencies.

Where CO₂ is stored via ex-situ mineralization of carbonate slurries or other such injectants, determination of the weight of CO₂-containing injectant delivered to the injection site may be performed using a calibrated scale. The total mass stored may be determined by the difference in delivery truck weight measured upon arrival at the injection facility and at departure, after offloading of product, either into closed-system temporary holding or directly stored.

Any truck scale used must have a current certification in accordance with applicable local, state, or federal regulations for legal-for-trade weights and measures. Testing and calibration of scales must utilize certified weights in accordance with local, state, or other regulations, calibration weights must meet NIST Handbook 44 specifications¹⁰ or similar national guidelines and specifications, and scale testing and calibration must be performed regularly (at minimum once annually) by a certified entity.

The Project Proponent must maintain the following records as evidence of gross CO₂e stored in injected CO₂ or CO₂-containing injectant:

• raw data provided via a CO₂ stream flow meter (volume and concentration measurements) for the Reporting Period, $RP$;
• records of any other mass measurements, such as weigh scale tickets;
• calibration records for all measurement equipment, including, but not limited to:
  • flow meters,
  • CO₂ analyzers, and
  • weigh scales;
• manufacturer operating manuals indicating required calibration procedures and frequency, as well as maintenance procedures and frequency for any measurement equipment;
• laboratory acCreditation records;
• laboratory analytical reports, including evidence of quality assurance and quality (QA/QC) activities;
• documentation of any spills during injection operations and estimates of quantity released; and
• reports of any instrument failures or down time.

Records of all analyses and injections must be maintained by the injection facility or Project Proponent and provided for verification purposes for a minimum of five years.

Type: Counterfactual

Refer to the Biomass Feedstock Accounting Module for calculation of counterfactual storage.

Type: Emissions

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

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

(Equation 3)

Where

• $CO_2e_{Emissions}$ represents the total GHG emissions for a Reporting Period, in tonnes of CO₂e.
• $CO_2e_{Establishment}$ represents the GHG emissions associated with project establishment, represented for the Reporting Period, in tonnes of CO₂e, see Section 7.4.4.1.
• $CO_2e_{Operations}$ represents the total GHG emissions associated with operational processes for a Reporting Period, in tonnes of CO₂e, see Section 7.4.4.2.
• $CO_2e_{End-of-Life}$ represents GHG emissions that occur after the Reporting Period and are allocated to a Reporting Period, in tonnes of CO₂e, see Section 7.4.4.3.
• $CO_2e_{Leakage}$ represents GHG emissions associated with the project’s impact on activities that fall outside of the system boundary of a project, over a given Reporting Period, in tonnes of CO₂e, see Section 7.4.4.4.

The following sections set out specific quantification requirements for each variable.

GHG emissions associated with project establishment 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 up until the first Reporting Period. Establishment emissions may be accounted for in the following ways, with the allocation method selected and justified by the Project Proponent:

• as a one time deduction from the first removal
• allocated to removals as annual emissions over the anticipated project lifetime
• allocated per output of product (i.e., per tonne CO₂ removed) based on estimated total production over project lifetime

The anticipated lifetime of the project should be based on reasonable justification and should be included in the Project Design Document (PDD) to be assessed as part of project validation.

Allocation of project establishment emissions to removals must be reviewed at each Crediting Period renewal and any adjustments made. If the Project Proponent is not able to comply with the allocation schedule described in the PDD e.g. due to changes in delivered volume or anticipated project lifetime, the Project Proponent must notify Isometric as early as possible in order to adjust the allocation schedule for future removals. If that is not possible, the Reversal process will be triggered in accordance with the Isometric Standard, to account for any remaining emissions.

GHG emissions associated with $CO_2e_{Operations}$ must include all emissions associated with operational activities, including but not limited to the SSRs set out in Table 1.

$CO_2e_{Operations}$ emissions occur over the Reporting Period for the deployment being Credited and are applicable to the current deployment only. $CO_2e_{Operations}$ 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.

$CO_2e_{End-of-Life}$ 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 $CO_2e_{End-of-Life}$ may occur from the end of the Reporting Period onwards, 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 $CO_2e_{Establishment}$.

Given the uncertain nature of $CO_2e_{End-of-Life}$ emissions, assumptions must be revisited at each Crediting Period and any necessary adjustments made. Furthermore, if there are unexpected $CO_2e_{End-of-Life}$ 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.

$CO_2e_{Leakage}$ 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 Biogenic CCS projects must account for market leakage emissions in accordance with the Biomass Feedstock Accounting Module.

$CO_2e_{Leakage}$ 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.

This section of the Protocol outlines requirements for EW emissions accounting relating to energy use, transportation, and embodied emissions associated with a CDR project.

Emissions associated with energy usage, whether through electricity or fuel use, must be accounted for throughout all phases of the process.

Energy related emissions 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
    • 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)
    • heat for capture process buildings and operations
  • heat utilization for thermal processes¹¹
  • 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
  • fuel used for heat generation or other purposes at the conversion or injection sites

Process emissions associated with the Project will be calculated by totalling 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 electrity 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 Biogenic 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 must be performed in accordance with the Energy Use Accounting Module, Section 3.2.6. Records & Required documentation must be performed in accordance with the Energy Use Accounting Module Section 3.2.7.

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 shall be calculated using the Energy Use Accounting Module Section 3.3 for fuel and waste heat utilization. Records and required documentation must be maintained in accordance with the Energy Use Accounting Module Section 3.3.4.

The Energy Use Accounting Module provides guidance 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.

Emissions related to transportation via freight transportation services, such as rail, truck, or maritime transport must be accounted for, including:

• Transport of biomass feedstock
• Transport of compressed gaseous or liquid CO₂ or CO₂ containing injectant (such as a carbonate slurry)

The Transportation Emissions Accounting Module provides guidance on how transportation-related emissions must be calculated in a CDR project so that they can be subtracted in the net CO₂e removal calculation. It sets out the calculation approach to be followed and acceptable emissions factors.

Embodied GHG emissions associated with the manufacturing, delivery, and installation of all equipment and consumables that lie within the system boundary must be accounted for in each Reporting Period. Embodied emissions are those related to the life cycle impact of equipment and consumables.

Examples of project-specific materials, equipment and consumables 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 scrubbers, adsorbers, or other contact equipment, sorbent regeneration
    • any sorbent, solvent, or other material handling systems, such as pumps, conveyors, augers, feed bins, and related equipment
    • any heat transfer equipment
    • captured CO₂ purification equipment
    • CO₂ compression and storage equipment (on-site)
    • 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:

    • any 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
    • CO₂ injection equipment, including compressors, pumps, and all wellbore equipment and materials

  • 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.
    • all instrumentation, controls, and other process management equipment

• Consumables, including:

  • Consumbales 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
      • proper disposal of used sorbents
    • heat transfer fluids such as thermal oils or refrigerants

  • CO₂ storage:

    • any feedstock or reactants used in the conversion of CO₂ to other products for storage
    • dilutants or additives used to support or improve injection of CO₂ or CO₂-containing product

  • 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

Embodied emissions for equipment used in the wider facility processes, CO₂ capture process, CO₂ transportation,or CO₂ storage must be included the the system boundary. In some cases universal equipment may excluded from the system boundary if the Project meets the eligiblity criteria for a narrow system boundary outlined in Table 2.

The Embodied Emissions Accounting Module sets out the calculation approach to be followed including allocation of embodied emissions, life cycle stages to be considered, data sources and emission factors.

Miscellaneous GHG emissions for emissions associated with a given Reporting Period are those not included in the SSR categories provided in Table 1. The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities. The Project Proponent must reporting such emissions as CO₂e_Misc..

Miscellaneous GHG emissions must consider direct emissions of non-CO₂ GHGs due to process leaks or fugitive emissions, releases, or GHG containing tailgas from:

• conversion processes
• degradation of sorbents or solvents

Quantification of emissions associated with direct emissions of non-CO₂e GHGs requires two primary measurements, the measurement of the total quantity of emissions and the analysis of emissions for CO₂ and other GHG content. This can be calculated as follows:

$$CO_{2}e_{MiscProjct} = \sum_{t=1}^{T} m_{em,t} \cdot\ C_{GHG,t} \cdot\ GWP_{GHG}$$

(Equation 4)

Where:

• $m_{em,t}$ = the mass of miscellaneous emission(s) (in tonnes) during $t$
• $C_{GHG,t}$ = the measured concentration as weight percent (%wt) of the relevant GHGs in the miscellaneous emission(s)
• $GWP_{GHG}$ = the global warming potential of the relevant GHGs for a 100-year time interval
• $t$ = the time index, ranging from 1 to $T$
• $T$ = $RP/Δt$, the number of time units in Reporting Period, $RP$
• $Δt$ = the time interval the average is taken over

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 gas¹², 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 concentration¹³'¹⁴;
• 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.

The Project Proponent must maintain the following records as evidence supporting calculation of emissions from the CO₂ conversion process:

• 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 Biogenic 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.

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

A Module for Ex-Situ Mineralization will be coming soon.

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

• Tim Hansen (350 Solutions); Biogenic Carbon Capture and Storage Protocol and Energy Use Accounting, Transportation Emissions Accounting and Embodied Emissions 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.
• Grant Faber (Carbon Based Consulting); Transportation Emissions Accounting Module.

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

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

Matthews, J.B.R. (Ed.). (2018). IPCC, 2018: Annex I: Glossary [Matthews, J.B.R. (ed.)]. 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

NIST (2015, April 20). Overview of ASTM D7036: A Quality Management Standard for Emission Testing. https://www.nist.gov/system/files/documents/2017/10/31/overview-astm-d7036.pdf

NIST. (2023). Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices - 2023 Edition. NIST. https://www.nist.gov/pml/owm/publications/nist-handbooks/handbook-44-current-edition

US Department of Energy. (2022) Best Practices for Life Cycle Assessment (LCA) of Direct Air Capture with Storage (DACS). https://www.energy.gov/sites/default/files/2022-06/FECM%20DACS%20LCA%20Best%20Practices.pdf

U.S. Environmental Protection Agency. (2023, April 18). Understanding Global Warming Potentials | US EPA. Environmental Protection Agency. Retrieved June 14, 2023, from https://www.epa.gov/ghgemissions/understanding-global-warming-potentials

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

Terlouw, T., Bauer, C., Rosa, L., Mazzotti, M. (2021). Life cycle assessment of CO₂ removal technologies: a critical review. Energy & Environmental Science. https://doi.org/10.1039/D0EE03757E

1. Shi, Xiaoyang, Hang Xiao, Habib Azarabadi, Juzheng Song, Xiaolong Wu, Xi Chen, and Klaus S. Lackner. "Sorbents for the direct capture of CO₂ from ambient air." Angewandte Chemie International Edition 59, no. 18 (2020): 6984-7006. ↩

2. Custelcean, Radu. "Direct air capture of CO₂ using solvents." Annual Review of Chemical and Biomolecular Engineering 13 (2022): 217-234. ↩

3. Fujikawa, Shigenori, and Roman Selyanchyn. "Direct air capture by membranes." MRS Bulletin 47, no. 4 (2022): 416-423. ↩

4. Renfrew, Sara E., David E. Starr, and Peter Strasser. "Electrochemical approaches toward CO₂ capture and concentration." ACS catalysis 10, no. 21 (2020): 13058-13074. ↩

5. For example, 40CFR195 - Transportation of Hazardous Liquids via Pipeline and 40CCF146.94 - Class VI Wells. ↩ ↩²

6. 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. ↩

7. ISO 14064-3: 2019, Section 5.1.7 ↩

8. https://​​carbonCreditquality​​.org​​/methodology​​.html ↩

9. Adefila, Kehinde, Yong Yan, Lijun Sun, and Tao Wang. "Flow measurement of wet CO₂ using an averaging pitot tube and coriolis mass flowmeters." International Journal of Greenhouse Gas Control 63 (2017): 289-295. https://doi.org/10.1016/j.ijggc.2017.06.005 ↩

10. https://www.nist.gov/pml/owm/nist-handbook-44-current-edition ↩

11. Lyons, L., Kavvadias, K. and Carlsson, J., Defining and accounting for waste heat and cold, EUR 30869 EN, Publications Office of the European Union, Luxembourg, 2021, ISBN 978-92-76-42588-5, doi:10.2760/73253, JRC126383. ↩

12. 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 ↩

13. Dinh, Trieu-Vuong, In-Young Choi, Youn-Suk Son, and Jo-Chun Kim. "A review on non-dispersive infrared gas sensors: Improvement of sensor detection limit and interference correction." Sensors and Actuators B: Chemical 231 (2016): 529-538. https://doi.org/10.1016/j.snb.2016.03.040 ↩

14. Sandoval-Bohorquez, Víctor Stivenson, Edwing Alexander Velasco Rozo, and Víctor G. Baldovino-Medrano. "A method for the highly accurate quantification of gas streams by on-line chromatography." Journal of Chromatography A 1626 (2020): 461355. https://doi.org/10.1016/j.chroma.2020.461355 ↩