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 sorption, liquid solvent, membrane processes, electrochemistry, etc.) in which a cradle-to-grave GHG Assessment can be accurately applied and in which the CO₂ captured is stored geologically (or via a method demonstrated to be equivalent) for >1000 years.

The protocol was developed in line with latest scientific understanding and industry best-practices which inform the quantification of gross CO₂ removed 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 CO₂e 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 1.0.0; 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 - Lifecycle Assessment - Principles & Framework; and
• ISO 14044: 2006 - Environmental Management - Lifecycle 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 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 that capture CO₂ from ambient air and store captured CO₂ geologically for >1000 years via processes (such as injection into saline aquifers and in-situ/ex-situ mineralization) to which cradle-to-grave GHG assessment can be accurately applied.

Projects that co-capture CO₂ from on-site point sources may not be accounted for as claimed removals, as they are not additional. DAC projects should not be co-located with emissions sources which result from the development, use, processing, or combustion of fossil fuels or petrochemicals. Co-located facilities are classified as those on contiguous or adjacent properties. In extenuating circumstances, such as those allowing for substantial gains in efficiency (e.g., via waste heat utilization) with little risk of non-additionality, co-location of facilities may be evaluated.

Only DAC projects which meet a zero emissions baseline (see Section 7.2) are eligible under this protocol. A project may qualify for this distinction by meeting one of the following conditions¹:

• 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);
• 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 3.7.1 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 (see Section 7.4 and the relevant storage modules for more information).
• The Project Proponent must have a CO₂ leak response plan in place that is 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 local, national or international regulations, for example by the EPA) that may be released as a result of sorbent or solvent degradation, volatilization, or aerosolization.
• Emission levels must be demonstrated by using, where possible, 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 local, national and international jurisdictions. 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 water consumption and water stress and have necessary mitigation activities in place to ensure water neutrality.

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 such as:

• information on power purchase agreements (PPAs) or other direct long term offtake agreements;
• GHG emissions associated with solvent/sorbent use; 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 Verification and Validation 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 as²:

• 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.

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 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 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 Removal Project Proponent should be able to demonstrate additionality through compliance with Section 2.5.3 of the Isometric Standard. The baseline utilized to assess additionality must be project-specific and is 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 credits³.

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 CO₂e removed over a reporting period ($RP$; see Section 7.3.1) for a project, $CO_2e_{Removal,\ RP}$, must be conservatively determined. Projects must comply with 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 carbonate slurries (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 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. However, that does not apply to any numerical data produced or used as part of the quantification of CO₂e removed.

The scope of this protocol includes the cradle-to-grave GHG Assessment of all emissions associated with the following aspects of a DAC and storage project for CO₂e removal, as summarized in Figure 1. A GHG Statement must be prepared, which must account for the following activities:

• DAC process, including:
  • DAC process operations,
  • DAC solvent/sorbent production and use, and
  • DAC process energy use and electricity grid considerations;
• CO₂ transport and temporary holding;
• CO₂ storage (including monitoring); and
• Embodied emissions associated with each process above, such as for manufacture or production, shipping, end-of-life disposal of process equipment and consumables, and any environmental remediation required during project closure.

Emissions for processes within the system boundary should include all GHG sinks and reservoirs 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 system, CO₂ transportation, CO₂ storage). Projects are required to include embodied emissions of both equipment and consumables in the process, as summarized in Figure 1.

Note that this protocol does not require inclusion of emissions resulting from ancillary activities not directly related to project operations, such as research and development activities, corporate administrative activities and any associated facilities. It does include activities associated with long term assurance of durable storage, including required monitoring activities and controls.

Carbon fluxes and associated GHG emissions and removals from the project may derive from, but are not limited to, the following sources:

• emissions of GHGs either as direct releases of GHGs from a process or storage system or as indirect emissions of GHGs from combustion of fuels, electricity generation, or other such sources;
• emissions of methane, primarily as indirect emissions of CH₄ from energy generation for processes or transportation due to combustion of fuels and/or electricity generation; and
• emissions of nitrous oxide, primarily as indirect emissions of N₂O from energy generation for processes or transportation due to combustion of fuels, electricity generation, or similar sources.

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 GHG (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.

As stipulated in Section 4, the baseline of qualifying projects is considered to be zero. The activity would not occur in a business as usual scenario, and there is no other business as usual counterfactual at this time for extraction of CO₂ from ambient air and its durable storage. Therefore, deduction of baseline CO₂e emissions is not included.

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 removals will pertain to all net emissions occurring over an interval of time. This unit of time is defined as the Reporting Period, $RP$, and is initially the time between injection commencing and verification and then between verifications.

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 $CO_2e_{Removal,\ RP}$.

Total emissions reductions may be adjusted in future years for a reporting period, $RP$, due to reversals (see Section 8) that may occur over the duration of the long-term storage period.

Net CO₂e removal for a process utilizing DAC with storage 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 (tonnes) for a given $RP$.
• $CO_2e_{Stored}$ = the gross total of CO₂e removed from the atmosphere (tonnes) for a given $RP$. See Section 7.4.1.
• $CO_2e_{Counterfactual}$ = the total quantity of counterfactual GHG emissions (tonnes), as total net GHG emissions associated with the total mass of CO₂ stored for a given $RP$. Note, for DAC with geologic storage, the counterfactual is 0. See Section 7.4.2.
• $CO_2e_{Emissions}$ = the total quantity of GHG emissions (tonnes) from operations and embodied emissions, as total net GHG emissions associated with the total mass of CO₂ stored for a given $RP$. See Section 7.4.3.

The final net CO₂e quantification must be conservatively determined, giving high confidence (95% or above) that the estimated mass of carbon was removed.

Type: Sequestration

$CO_2e_{Stored}$ represents the mass of carbon 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 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 carbon content divided by the fraction of carbon 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 carbon:
  • ${C_{inj}}$ (%wt of CO₂ in the CO₂ injection stream or %wt carbon within a carbonate solution divided by carbon content in CO₂ (0.2727), 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
• 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%)⁴,
  • recorded at a frequency of 1-second 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.
• Where it is not possible to collect continuous measurements and the CO₂ flow is stable, a minimum of three samples must be collected quarterly. The carbon 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 injectate will also be subject to random sampling, to alleviate the risk of any of the stream having a substantially different carbon 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 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.

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 carbon 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;
• ASTM D513-16: Standard Test Methods for Total and Dissolved Carbon Dioxide 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.

Tests 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 samples must be collected for each sampling event and for stable carbon mass flows, at a minimum this sampling must occur quarterly. The carbon 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 any substantially different carbon content at 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 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 (i.e. NIST);
• 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.

Ex-situ mineralization may use carbonate slurries or other such injectants are produced, determination of weight of delivered CO₂-containing injectant 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 specifications⁵, and scale testing and calibration must be performed by a state certified entity.

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

• a CO₂ stream flow meter and concentration measurement that provides raw data 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 carbon content analyses and injections must be maintained by the injection facility or project proponent and provided for verification purposes for a period of five years.

Type: Counterfactual

For DAC with geologic sequestration, the counterfactual is considered to be 0 if all eligibility criteria are met and conditions outlined in Section 4 are also met.

However, there are considerations for counterfactual energy usage, which are discussed and accounted for within the Energy Use Accounting Module (see Section 7.4.3.1).

Type: Emissions

$CO_2e_{Emissions}$ is is the total quantity of GHG emissions from operations and embodied emissions associated with the injections that occurred in reporting period, $RP$. This can be calculated as:

$$CO_{2}e_{Emissions} = CO_{2}e_{Energy} + CO_{2}e_{Transportation} \\ + CO_{2}e_{Embodied} + CO_{2}e_{Misc. Project} + CO_2e_{Monitoring}$$

(Equation 3)

Where:

• $CO_2e_{Emissions}$ = the total quantity of GHG emissions from operations and embodied emissions for a given $RP$, in tonnes;
• $CO_2e_{Energy}$ = the total quantity of GHG emissions associated with energy consumption for a given $RP$, in tonnes, see Section 7.4.3.1;
• $CO_2e_{Transportation}$ =the total quantity of GHG emissions associated with transportation of products for a given $RP$, in tonnes, see Section 7.4.3.2;
• $CO_2e_{Embodied}$ = the total quantity of embodied GHG emissions allocated to a given $RP$, in tonnes, see Section 7.4.3.3;
• $CO_2e_{Monitoring}$= the total quantity of GHG emissions associated with storage monitoring allocated to a given $RP$, in tonnes, see the relevant Storage Modules in Section 8 for calculation details; and
• $CO_2e_{Misc.\ Projects}$ = the total quantity of miscellaneous GHG emissions for a given $RP$, that cannot be categorized by $CO_2e_{Energy}$, $CO_2e_{Transportation}$, $CO_2e_{Embodied}$ or $CO_2e_{Monitoring}$, in tonnes, see Section 7.4.3.4.

Emissions associated with energy usage throughout all phases of the process must be accounted for, whether electricity or thermal energy, typically associated with 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, 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)
    • sorbent/solvent or other regeneration process (thermal)
    • heat for DAC process buildings and operations
  • heat utilization for thermal processes⁶
  • 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 Sequestration
  • 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 Storage & Monitoring
  • electricity for pumps, motors, drives, etc.
  • electricity for instrumentation, controls, analyzers, etc.
  • electricity for building operation & management for monitoring facility buildings

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; and
• emissions associated with transportation of compressed gaseous or liquid CO₂ or CO₂ containing injectant (such as a carbonate slurry) via freight transportation services, such as rail, truck, or maritime transport.

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 over an appropriate allocation period.

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 specifically built for transportation of CO₂, including pipelines, and any pumps or compressors. This excludes mobile sources such as trucks, ships, or rail,
  • CO₂ sequestration:
    • 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
  • CO₂ monitoring:
    • all monitoring equipment, including instrumentation, pumps, sampling equipment
    • monitoring wells installed or used for the monitoring of storage systems
  • 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, equipment and facilities, 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 sequestration:
    • 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
  • CO₂ monitoring:
    • gases used for operation or calibration of monitoring equipment
    • analytes, reagents, or other products used for analytical testing of samples for monitoring parameters
    • consumable sampling equipment or supplies that are used in significant quantities
  • Universal equipment 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

Miscellaneous GHG emissions for emissions associated with injections for a given reporting period, that cannot be categorized by $CO_2e_{Energy}$, $CO_2e_{Transportation}$, $CO_2e_{Embodied}$ or $CO_2e_{Monitoring}$.

Projects are responsible for identifying and quantifying such emissions. Examples include, but are not limited to:

• direct emissions of CO₂ due to process leaks or fugitive emissions such as venting during transportation
• 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
• emissions of sorbents or solvents as carryover or directly, if they have a 100 yr GWP > 1

Emissions for the above examples are 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

Quantification of $CO_2e_{Misc. Project}$ in a given $RP$, requires two primary measurements, the measurement of the total quantity of emissions and the analysis of emissions for CO₂ and other GHG content.

The total quantity of emissions can be determined 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 gas⁷, 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 local, national or international regulatory authority to perform compliance emissions testing. 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 the emissions ($CO_2e_{Release}$) or tail gas ($CO_2e_{Tailgas}$) 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 concentration⁸'⁹;
• 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 local, national or international regulatory authority to perform compliance emissions testing. 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:

• 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.

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 and Embodied Emissions modules.
• 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 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 modules.

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

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

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

2. ISO 14064-3: 2019, Section 5.1.7 ↩

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

4. 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 ↩

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

6. 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. ↩

7. 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 ↩

8. 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 ↩

9. 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 ↩