Direct Air Capture

This protocol provides the requirements and procedures for the calculation of net carbon dioxide equivalent (CO₂e) removals from the atmosphere via Direct Air Capture (DAC). This protocol is developed for application to DAC processes or combinations of processes (e.g., solid sorption¹, liquid solvent², membrane processes³, electrochemistry⁴, etc.) in which a cradle-to-grave greenhouse gas (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 was developed in line with latest scientific understanding^{7 8 9} and industry best-practices^{10 11} which inform the quantification of gross CO₂ durably captured and stored via DAC as well as the accounting of GHG emissions associated with DAC processes. Additionally, 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 DAC and CO₂ storage. Because DAC is still a developing approach to carbon dioxide removal (CDR) with ever-expanding published literature, the protocol incorporates requirements that may be more stringent than some current regulations or other protocols related to DAC and CO₂ storage. The approach taken here may be altered in future versions of the protocol as DAC and CO₂ storage technology and research advance.

This protocol applies to projects anywhere that capture CO₂ from ambient air and store captured CO₂ for >1000 years via physical or chemical trapping mechanisms laid out in the relevant CO₂ Storage Module. A cradle-to-grave GHG Statement must also be able to be accurately applied to all processes within the scope of the project.

To ensure long-term durability, CO₂ characteristics and the conditions within the storage reservoir must be well defined, modeled and planned to be monitored in line with jurisdictional post-closure requirements. Evidence that CO₂ will be trapped via the intended method and within the intended reservoir with no free phase migration after closure (as per regulating permitting requirements) is needed to support that carbon dioxide can be durably stored.

Projects that co-capture CO₂ from on-site point sources may not be accounted for as claimed removals, as this constitutes an avoided emissions project, not a removal. DAC projects that are co-located, defined here as being within 1km distance, with major emissions sources originating from the development or combustion of fossil fuels or petrochemicals, are only eligible if the project proponent uses isotope tracing of the captured CO₂ to enable accounting of only non-fossil CO₂ in such locations. Atmospheric dispersion modeling¹² and biogenic carbon monitoring of the captured CO₂ may provide support for this evaluation.

Only DAC projects which meet a zero emissions baseline scenario (see Section 7.2) are eligible under this protocol. A project may qualify for this distinction by meeting one of the following conditions¹³:

• no capture facility existed at the capture facility location prior to the start of the project activity (greenfield capture facilities);
• new capture facilities or expanded capture facilities are installed at an existing capture facility location (expansion of existing capture facilities); and
• an existing capture facility would be decommissioned prior to the start of the project activity (refurbishment of an existing capture facility).

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 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 regulations¹⁴ (see Section 7.4.1 and 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 requirements¹⁴ 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 DAC 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, and with high concentrations of CO₂.
• 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 neutrality¹⁵.

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 DAC, for example:

• information on power purchase agreements (PPAs) or other direct long term offtake agreements;
• 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 7, 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 as¹³:

• 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 DAC project 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 relevant sectoral scope accreditations listed below, based on IAF MD 14 and in accordance with Isometric's VVB policy:

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

CDR via DAC 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 net 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;
• 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 credits¹⁶.

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 7.3.1) 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 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 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. That 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 emissions 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 the GHG sources, sinks, and reservoirs (SSRs) associated with a DAC project.

A cradle-to-grave GHG Statement must be prepared encompassing the GHG emissions relating to the activities associated with a DAC and storage project for net CO₂e removal, as summarized in Figure 1 and described below:

• DAC process: All activities that take place associated with sequestering atmospheric CO₂
• CO₂ transportation: All activities associated with transporting CO₂ from the DAC plant to the storage location
• CO₂ storage: All activities that take place associated with the permanent storage of CO₂ at the storage location.
• CO₂ monitoring: All activities related to monitoring CO₂ storage

Emissions for processes within the system boundary should include all GHG SSRs from the construction or manufacturing of each project and associated equipment, closure of each project and disposal of associated equipment, and operation of each process (DAC process, CO₂ transportation, CO₂ storage and CO₂ monitoring).

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.

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. 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: carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), and fluorinated gasses such as hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF₆), and nitrogen trifluoride (NF₃).

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).

The above greenhouse gases must be included in emission calculations for each calculation term identified in Figure 1, according to the following guidelines:

Calculation terms shaded in blue must account for potential emissions of CO₂ and other GHGs (e.g., CH₄, and N₂O) via use of appropriate emission factors and conversion to CO₂e.

Calculation terms shaded in green must account for potential emissions of CO₂ only, as no other GHG emissions are expected from these types of sources.

The baselines scenario for a DAC project assumes the activities associated with the project do not take place and any associated infrastructure is not built.

The counterfactual for DAC projects considers quantification of the CO₂ that would have been removed from ambient air via a DAC process and durably stored over the same domain in the absence of the project. As stipulated in Section 4, the counterfactual of qualifying projects is considered to be zero.

DAC 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 DAC systems, the equations below used to calculate net CO₂e removals will pertain to all CO₂ removals and GHG emissions that occur over an interval of time. This unit of time is defined as the Reporting Period, $RP$, which represents an interval of time over which net CO₂e removals are calculated and reported for verification.

The following sections outline the process for calculating the net CO₂e removed for each reporting period, written hereafter as $CO_2e_{Removal,\ RP}$.

Net CO₂e removal for a process utilizing DAC 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 for a given $RP$, in tonnes of CO₂e.
• $CO_2e_{Stored}$ = the total CO₂ removed from the atmosphere and durably stored over the $RP$, in tonnes of CO₂e. See Section 7.4.1.
• $CO_2e_{Counterfactual}$ = the total counterfactual CO₂ removed from the atmosphere and durably stored in the absence of the project over the $RP$, in tonnes of CO₂e. Note, for DAC with geologic storage, the counterfactual is 0. See Section 7.4.2.
• $CO_2e_{Emissions}$ = the total GHG emissions associated with the $RP$, in tonnes of CO₂e. See Section 7.4.3.

Note: Reversals occur after Credits have been issued so are not included in this equation. See Section 5.6 of the Isometric Standard for further infomartion. Risk of reversal information is provided within the relevant Storage Module.

Type: Sequestration

$CO_2e_{Stored}$ represents the amount of CO₂ 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 the additional carbonate concentration in the carbonated minerals
• $m_{Inj,t}$ = 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).

${C_{inj}}$ measurement can be calculated in two different ways depending on how it is being stored. CO₂ streams that are being injected into wells must be measured following Section 7.4.1.2, whilst CO₂ being stored by ex-situ mineralization must be calculated following Section 7.4.1.3.

The concentration of CO₂ in the gaseous, dissolved 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 DAC 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%)¹⁷,
  • 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, but which in any case must be no less than annual, 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.

The total CO₂ content must be determined using the difference in carbonate concentration in the mineral waste pre and post mineralization. This should be carried out in line with the following standard following:

• ISO 10694:1995 - Determination of organic and total carbon after dry combustion (elementary analysis)
• 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 10694 accredited laboratory, or equivalent, with accreditation including the specific method of interest.

All samples must be collected as individual grab samples from the mineralized material. Project Proponents must conduct sampling such that variability in carbonated materials is characterized; sampling strategies must be reported and justified in the PDD. Further guidance on sampling of heterogeneous materials is given in Section 4 of the Rock and Mineral Feedstock Characterization Module. At a minimum, samples must be taken daily whilst the ex-situ process is ongoing.

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.

Laboratory quality assurance data shall be used in determination of uncertainty in accordance with Section 6.5.

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 minute 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, determination of the mass of CO₂ of the material that had undergone ex-situ mineralisation shall be measured using calibrated scale. This could for example be done by determining the difference in delivery truck weight measured upon arrival at the final storage facility and at departure, after offloading of product, either into closed-system temporary holding or directly stored, or using load cells/sensors on temporary holding tanks. Any 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 specifications¹⁸, and scale testing and any calibration must be performed regularly (at minimum once annually) by a certified entity.

In general, the Project Proponent must identify, notify and explain any data gaps or missing calibration data, if any occur. The Project Proponent notify Isometric and the VVB when data gaps or missing calibration data occur and must clearly explain the approach taken and document the missing data within the GHG statement.

For those parameters where frequent, sub-hourly measurements are required (notably CO₂ concentration measurements in the CO₂ stream, and the measurement of mass of CO₂ injected), the Project Proponent must adhere to the following procedure for handling missing data.

Where there are data gaps in measurement of the relevant parameter of up to 30 minutes, the Project Proponent may claim using an average quantity, based on the measurements proceeding and following the data gap.

Where there are such data gaps of longer than 30 minutes, the Project Proponent may apply this approach for up to a 30 minute period within the duration of the data gap, but no more than this. For the remainder of the period of the data gap, i.e. in excess of 30 minutes, no carbon dioxide removal may be claimed, due to a lack of data. In addition, data gaps must account for less than 5% of the data used for the removal calculation within a given reporting period, any missing data above this is also not creditable.

Where a calibration is missed, one must be completed as soon as this is noticed. For data collected between when the calibration was required and when it actually took place, a conservative estimate should be used agreed between the VVB, project proponent and Isometric.

The project proponent must maintain the following records as evidence of gross CO₂ 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, $RP$;
• analytical results for each supporting gaseous or carbonated injectant analysis specified in Section 7.4.1;
• 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

For DAC with geologic sequestration, the counterfactual for eligible projects is considered to be zero, as outlined in Section 4.

Type: Emissions

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

$$CO_{2}e_{Emissions} = CO_{2}e_{Energy} + CO_{2}e_{Transportation} \\ + CO_{2}e_{Embodied} + CO_{2}e_{Misc.} + CO_{2}e_{Leakage}$$

(Equation 3)

Where:

• $CO_2e_{Emissions}$ = the total GHG emissions for a given $RP$, in tonnes of CO₂e;
• $CO_2e_{Energy}$ = the total GHG emissions associated with energy consumption for a given $RP$, in tonnes of CO₂e, see Section 7.4.3.2;
• $CO_2e_{Transportation}$ = the total GHG emissions associated with transportation for a given $RP$, in tonnes of CO₂e, see Section 7.4.3.3;
• $CO_2e_{Embodied}$ = the total embodied GHG emissions allocated to a given $RP$, in tonnes of CO₂e, see Section 7.4.3.4;
• $CO_2e_{Misc.}$ = the total miscellaneous GHG emissions for a given $RP$, that cannot be categorized by $CO_2e_{Energy}$, $CO_2e_{Transportation}$, or $CO_2e_{Embodied}$, in tonnes CO₂e, see Section 7.4.3.5; and
• $CO_2e_{Leakage,\ n}$= the total GHG emissions associated with the project’s impact on activities that fall outside of the system boundary of a project, allocated to a given $RP$, in tonnes of CO₂e, see Section 7.4.3.6.

Emissions that occur during a Reporting Period, $RP$ must be included directly and fully in that Reporting Period, and not allocated across multiple Reporting Periods.

Embodied emissions which relate to multiple Reporting Periods may be allocated to removals in line with the allocation rules set out in the Embodied Emissions Accounting Module.

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

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

GHG emissions associated with $CO_2e_{Energy}$ should include all emissions associated with electricity usage or fuel combustion.

Energy related emissions may include, but are not limited to:

• DAC 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 DAC process 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 DAC process buildings and operations
  • heat utilization for thermal processes¹⁹
  • 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
• CO₂ Monitoring
  • electricity used for monitoring equipment operation, including analyzers, instrumentation, on-site laboratories specifically for monitoring activities
  • electricity used for sampling pumps, sampling systems, or other similar monitoring activities
  • electricity used for off site analytical laboratory operation and sample analysis
  • electricity used for monitoring system installation (if not accounted for in project embodied emissions) and operation, such as electricity used for temperature control of monitoring systems (heat trace)
  • electricity for building operation & management for monitoring facility buildings
  • fuel used for sampling system operation, such as any pumps or heating systems
  • fuel used for any handling equipment, such as fork trucks or loaders, which are used during sample collection and processing
  • fuel used during monitoring system installation, operation or closure, such as that used by drill rigs

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.

Electricity usage associated with the DAC process/facility must follow the $CO_2e_{Electricity,\ R}$ calculation approach for intensive facilities whilst all other processes may follow the calculation approach for non-intensive processes/facilities.

Emissions related to transportation of CO₂ or injectants for all injections during a reporting period must be accounted for, including the following:

• emissions associated with transportation of captured CO₂ from DAC site to injection site via pipeline;
• emissions associated with transportation of compressed gaseous or liquid CO₂ or CO₂ containing injectant (such as a carbonate slurry) or carbonated minerals via freight transportation services, such as rail, truck, or maritime transport; and
• transportation of samples for lab analysis.

The Transportation Emissions Accounting Module provides guidance 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 and approach to be followed and acceptable emissions factors.

Embodied GHG emissions associated with the manufacturing, delivery, and installation of all equipment and consumables used in the DAC process must be accounted for in each $RP$. The Project Proponent must identify all equipment and consumables used in the DAC process, identify appropriate cradle to grave emission factors, and allocate the emissions to removals appropriately in line with the Embodied Emissions Accounting Module.

Project Proponents must account for all embodied emissions in DAC equipment and facilities, including but not limited to the following:

• Equipment, including:

  • DAC Process:

    • DAC Process equipment, including fans, 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

  • Monitoring:

    • monitoring wells and all associated materials (steel casing, concrete, etc.)
    • on-line analyzers, measurement equipment, or other such devices
    • 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.
    • all instrumentation, controls, and other process management equipment

Heat generation equipment and heat transfer equipment must be accounted for, but embodied emissions may already be accounted for by emission factors used for fuel combustion (i.e., steam boiler) emissions consider full cradle-to-grave GHG emissions. Project Proponents should evaluate whether embodied emissions from equipment such as boilers are included in the energy emissions calculations, and if not, account for the embodied emissions here.

Project Proponents must account for all embodied emissions in DAC process consumables including but not limited to the following:

• Consumables, including:

  • DAC 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
    • dilutents 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
    • consumable sampling equipment or supplies that are used in significant quantities

  • Universal consumerables for all processes:

    • gasses 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

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

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

GHG emissions associated with $CO_2e_{Misc.}$ should include all project emissions that cannot be categorized by $CO_2e_{Energy}$, $CO_2e_{Transportation}$, or $CO_2e_{Embodied}$. The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities, including associated with any activities additional to those set out in Section 7.1. The Project Proponent must report such emissions as $CO_2e_{Misc.}$.

Examples include, but are not limited to:

• 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
  • any other source of potential GHG emissions not of the CO₂ collected from the ambient air or not addressed in $CO_2e_{Energy}$, $CO_2e_{Transportation}$, or $CO_2e_{Embodied}$ terms
• waste processing associated with all aspects of the DAC process, CO₂ transport, CO₂ storage and monitoring
• staff travel associated with the project

Quantification of $CO_2e_{Misc. Project}$ in a given $RP$ should be undertaken in line with the requirements set out in the Energy Use Accounting Module, the Transportation Emissions Accounting Module and the Embodied Emissions Accounting Module, where appropriate.

Quantification of emissions associated with direct emissions of non-CO₂ 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 gas²⁰, 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 CO₂ or other GHGs in emissions must be measured directly via one of the following methods:

• on-line analyzer measurement of CO₂ or 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 CO₂ and GHGs within +/- 30% of expected average tail gas concentration^{21 22};
• 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 DAC or 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 DAC 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.

$CO_2e_{Leakage,\ n}$ includes emissions associated with a project's impact on activities outside the system boundary of the project. This includes instances where the Project causes an increase in GHG emissions by diverting material from other uses or incentivizing increased production activity.

It is the Project Proponent's responsibility to identify potential sources of leakage emissions. For a DAC project, market leakage emissions associated with the replacement of consumables used must be considered as a minimum.

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); Direct Air Capture Protocol and Energy Use Accounting, Transportation Emissions Accounting and Embodied Emissions Accounting Modules.
• Chris Holdsworth, Ph.D. (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.

Isometric would like to thank following reviewers of this Protocol and relevant modules:

• James Campbell, Ph.D. (Herriot Watt University); Direct Air Capture Protocol and CO₂ Storage via In-Situ Mineralization in Mafic and Ultramafic Formations Module.
• Grant Faber (Carbon Based Consulting); Energy Use Accounting and Embodied Emissions Accounting Modules.

This appendix details how the Project Proponent must monitor, document and report all metrics identified within this Protocol. Following this guidance will ensure the Project Proponent measures and confirms carbon removed and long-term storage compliance, and will enable quantification of the emissions removal resulting from the Project activity during the Project Crediting Period, prior to each Verification.

This methodology utilizes a comprehensive monitoring and documentation framework that captures the GHG impact in each stage of a Project. Monitoring and detailed accounting practices must be conducted throughout to ensure the continuous integrity of Crediting.

The Project Proponent must develop and apply a monitoring plan according to ISO 14064-2 principles of transparency and accuracy that allows the quantification and evidencing of GHG emissions and CO₂ removals.

The Modules associated with this Protocol have their own set of required parameters that need to be monitored. Please refer to the following Sections of the Modules to see a complete list of all requirements:

• CO₂ Storage in Saline Aquifers Module 1.0
• CO₂ Storage via In-situ Mineralization in Mafic and Ultramafic Formations 1.0

These parameters must be monitored for the purpose of Carbon Emissions Calculation and Embodied Carbon Emissions Calculation.

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 Carbon Dioxide 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

U.S. DOE. (2022). Best Practices for Life Cycle Assessment (LCA) of Direct Air Capture with Storage (DACS). U.S. Department of Energy, Office of Fossil Energy and Carbon Management. https://www.energy.gov/fecm/best-practices-LCA-DACS

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 carbon dioxide 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. Al Hameli, Fatima, Hadi Belhaj, and Mohammed Al Dhuhoori. "CO2 sequestration overview in geological formations: Trapping mechanisms matrix assessment." Energies 15, no. 20 (2022): 7805. ↩

6. Rochelle, Christopher A., I. Czernichowski-Lauriol, and A. E. Milodowski. "The impact of chemical reactions on CO2 storage in geological formations: a brief review." Geological Society, London, Special Publications 233, no. 1 (2004): 87-106. ↩

7. Ricks, Wilson, Qingyu Xu, and Jesse D. Jenkins. "Minimizing emissions from grid-based hydrogen production in the United States." Environmental Research Letters 18, no. 1 (2023): 014025. ↩

8. Goeppert, Alain, Miklos Czaun, GK Surya Prakash, and George A. Olah. "Air as the renewable carbon source of the future: an overview of CO 2 capture from the atmosphere." Energy & Environmental Science 5, no. 7 (2012): 7833-7853. ↩

9. Sanz-Pérez, Eloy S., Christopher R. Murdock, Stephanie A. Didas, and Christopher W. Jones. "Direct capture of CO2 from ambient air." Chemical reviews 116, no. 19 (2016): 11840-11876. ↩

10. Terlouw, Tom, Karin Treyer, Christian Bauer, and Marco Mazzotti. "Life cycle assessment of direct air carbon capture and storage with low-carbon energy sources." Environmental science & technology 55, no. 16 (2021): 11397-11411. ↩

11. Erans, María, Eloy S. Sanz-Pérez, Dawid P. Hanak, Zeynep Clulow, David M. Reiner, and Greg A. Mutch. "Direct air capture: process technology, techno-economic and socio-political challenges." Energy & Environmental Science 15, no. 4 (2022): 1360-1405. ↩

12. Turnbull, Jocelyn Christine, Elizabeth D. Keller, Margaret W. Norris, and Rachael M. Wiltshire. "Independent evaluation of point source fossil fuel CO2 emissions to better than 10%." Proceedings of the National Academy of Sciences 113, no. 37 (2016): 10287-10291. ↩

13. Criteria provided in Verra 2023 Draft DAC Module: https://verra.org/wp-content/uploads/2023/06/DAC-Module-Public-Consultation-Draft.pdf ↩ ↩²

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

15. 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. ↩

16. https://​​carboncreditquality​​.org​​/methodology​​.html ↩

17. 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 ↩

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

19. 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. ↩

20. 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 ↩

21. 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 ↩

22. 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 ↩