CRCF Isometric Bio-CCS Requirements

This Module is developed for issuing Credits under the EU Carbon Removal and Carbon Farming (CRCF) framework established by EU Regulation 2024/3012.

The CRCF+ Bio-CCS Protocol v1.0 contains the core requirements for Bio-CCS according to the CRCF Delegated Act Annex methodologies. This supplementary Module contains the relevant additional Isometric requirements from our Bio-CCS Protocol. Any Isometric requirements entirely satisfied by the CRCF Delegated Act Annex methodologies are omitted. Those partially satisfied have been reformulated to build on the framework from the CRCF methodologies.

Activities where more than 5% of feedstocks by mass are fossil fuels shall provide a justification for the necessity of these feedstocks within the context of the carbon dioxide removal (CDR) Activity at the Certification Audit if applicable to the whole Activity lifetime, or at the Re-certification Audit if related to a specific Activity Period only.

The Operator shall provide evidence that the Activity will do no net environmental or social harm by complying with the Environmental and Social Impacts section of the Isometric Standard.

In relation to the environmental sustainability requirements outlined in the Isometric Standard and CRCF+ Bio-CCS Protocol v1.0, the Operator shall provide evidence of the following:

• The Operator shall demonstrate that emissions of solvents and/or sorbents, including of the following types, are below regulatory limits, where applicable:
  • 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 Annex II of the Industrial Emissions Directive 2010/75/EU) that may be released as a result of sorbent or solvent degradation, volatilization, or aerosolization.
• Emission levels of solvents and/or sorbents shall be demonstrated by using, where possible and reasonable, national or international standard test and sampling methods (i.e., ISO, NIST, ASTM, EPA), and should be completed by a qualified testing organization. Operators shall keep such records on file and repeat testing when substantial changes occur that may impact emissions (for example, to solvent or sorbent formulations or operating conditions).
• The Operator shall monitor water consumption and water stress, evaluate risks and implement necessary mitigations to ensure the Activity does not have significant impact on bodies of water, including groundwater.

In relation to the social impact requirements outlined in the Isometric Standard and CRCF+ Bio-CCS Protocol v1.0, the Operator shall demonstrate that they have addressed any specific hazards associated with the use, handling and transportation of the proposed sorbent or solvent in line with the Chemical Handling Directive 2014/27/EU and associated regulations.

Proper handling of waste and by-product outputs from combustion processes is essential to reducing environmental and public health risks. Therefore, all wastes and residues from combustion processes that comprise part of the CDR process shall be managed to ensure these risks are effectively controlled.

Activities handling incineration residues shall follow the requirements outlined within the EU Waste Incineration Directive (WID) and the Industrial Emissions Directive (IED) unless more rigorous standards are applicable locally. Operators of such Activities shall provide evidence of responsible waste handling in relation to each of the following incineration residues:

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

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

Operators shall use best available techniques to monitor and reduce flue gas emissions in compliance with the EU Industrial Emissions Directive (IED) and the limits detailed in EU Directive 2010/75/EU Annex VI Part 3, or the relevant local legislation if it is more stringent.

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

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

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

Site visits to project facilities shall be carried out in accordance with the requirements of ISO 14064-3, 6.1.4.2, at least once during each Certification Audit.

Additional site visits may be required if there are substantial changes to field operations over the course of a Certification Period, or if deemed necessary by the Certification Scheme or the Certification Body. Site visit plans are to be determined according to the Certification Body's internal assessment, in consultation with the Certification Scheme.

Verifiers should whenever possible observe operation of the capture and storage processes to ensure full documentation of process inputs and outputs through visual observation and validation of instrumentation, measurements, and required data quality measures.

The Operator shall be able to demonstrate additionality through compliance with the Additionality section of the Isometric Standard.

Additionality determinations should be reviewed and completed every 15 years (aligned with the Activity Period), at a minimum, or whenever operating conditions change significantly, such as the following:

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

Any review and change in the determination of additionality should not affect the availability of Carbon Finance and Verified Credits for the current or past Activity Periods, but if the review indicates the Activity has become non-additional, this will make the Activity ineligible for future Credits.¹

Operators shall 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; 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 the Isometric Standard.

In addition, a sensitivity analysis that demonstrates the impact of each input parameter’s uncertainty on the final net CO₂e uncertainty shall be provided. Details of the method for sensitivity analysis shall 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 shall be specified.

The CRCF+ Bio-CCS Protocol v1.0 outlines calculation methodologies to determine the net CO₂ removal ($CR_{total}$) in line with the CRCF framework. The following sections provide additional requirements and guidance to be applied to these calculations.

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

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

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

Once $F_{B}$ is determined in accordance with Method A or B, the amount of biogenic CO₂ captured $CO_{2}e_{captured}$ and the subsequent total carbon removal ($CR_{total}$) shall be determined using the calculation methodologies outlined in the CRCF+ Bio-CCS Protocol v1.0.

$F_{B}$ shall be determined by

• Flue sampling location according to ISO 10396/EN 15259 or ASTM D7459.
  • Flue gas sampling may be on the pre-capture or post-capture CO₂ stream.
• Flue sampling according to EN 14181 or ASTM D7459.
• Representative flue gas samples shall be taken continuously, integrated over a maximum of a 3 months of operations, by an extractive CEMS.
• Flue gas samples shall be demonstrated to be proportionally matched to the flue stack gas mass flow during collection.
• From these samples, the biogenic fraction ($F_{B}$) shall be determined by radiocarbon sampling and determination using ISO 13833:2013 or ASTM D6866-21.
• This Method is aligned with Tier 3 from the ETS MRR Implementing Regulation 2018/2066 Annex II §2.4.

$F_{B}$ shall be conservatively determined using a carbon mass balance approach detailed by Equation 1.

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

(Equation 1)

where

• $m_{Biomass,i}$ is the measured dry mass of biomass feedstock, i, used by the Activity within a Certification Period.
• $C_{Biomass,i}$ is the CO₂e of biomass feedstock, i.
• $N_B$ is the total number of biomass feedstocks used in a Certification Period.
• $m_{FF,i}$ is the measured mass of fossil fuel, i, used by the Activity within a Certification Period.
• $C_{FF,i}$ is the CO₂e of fossil fuel, i.
• $N_{FF}$ is the total number of fossil fuel feedstocks used in a Certification Period.
• This Method is aligned with Tier 2 from the ETS MRR Implementing Regulation 2018/2066 Annex II §2.4.

For the Certification Audit, all Operators shall estimate an average $F_{B}$ based on:

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

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

The mass of CO₂-containing fluid captured over defined time interval (Δt), $m_{cap,t}$, may either be:

(a) directly measured using a mass flow meter, or

(b) indirectly measured by combining suitable volume and density measurements.

In case (a), preference is for high-accuracy flow meters such as coriolis or thermal mass flow meters, although other metering solutions are allowable. Flow metering should meet the following requirements:

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

In case (b), the mass is calculated as:

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

(Equation 2)

Where:

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

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

Alternative methods of measuring the mass of CO₂ captured, which are aligned with the principles and requirements of Implementing Regulation (EU) 2018/2066, may be applied in agreement with the Certification Scheme.

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

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

Alternative methods of measuring the concentration of CO₂, which are aligned with the principles and requirements of Implementing Regulation (EU) 2018/2066, may be applied in agreement with the Certification Scheme.

Operators shall follow the procedure in the MRR Articles 44 - 45 for handling missing data where required by the Protocol. This section details how to handle data gaps in any other measurements or data reported to the Certification Scheme.

The Operator shall identify, highlight and justify any data gaps and missing calibration data should they occur. The Certification Scheme and the Certification Body shall be notified of data gaps and missing calibration data as soon as they become evident. Documentation that explains the approach taken and details the missing data shall be provided to the Certification Scheme and the Certification Body and included in the GHG Statement.

For parameters that require sub-hourly measurements, the Operator shall adhere to the following procedure for handling missing data events:

• Where data gaps in measurements are 30 minutes or less in duration, the Operator shall use an average measurement utilising measurements taken 30 minutes prior to and following the data gap.
• Where data gaps in measurements are longer than 30 minutes in duration, the Operator shall apply the above approach for up to a 30 minute period within the duration of the data gap only. For the remaining duration of the data gap the Operator shall assume a conservative stance in consultation with the Certification Scheme, depending on the nature of the data loss as detailed below:
  • If the data loss pertains to the capture of biogenic CO₂, no carbon dioxide removal can be claimed due to the lack of data.
  • If the data loss pertains to GHG emissions, for example, from the flue stack to the atmosphere, the Operator shall assume a maximum value for the release of GHG emissions identified from the 24 hours prior to, and the 24 hours following the data gap.
  • If the data loss pertains to $F_{B}$, the Operator may justify the use of an averaged $F_{B}$ based on comparable historic data for the feedstock type and time period. This justification will require evidence of low variability in $F_{B}$ over comparable periods to the data gap, and shall be a conservative estimation by subtracting the standard deviation of the averaged or historical data.

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

Where calibrations are missed, one shall be completed as soon as this becomes evident. For data collected between when the calibration was required and when it took place, a conservative estimate should be agreed between the Certification Body, the Operator, and the Certification Scheme.

For Bio-CCS Activities capturing both fossil and biogenic CO₂, certain project emissions ($GHG_{associated}$) are associated with shared processes and equipment. The CRCF+ Bio-CCS Protocol v1.0 gives details of how these project emissions may be allocated proportionally between biogenic and non-biogenic fractions.

Under Isometric CRCF+ requirements, project emissions ($GHG_{associated}$) by default shall be fully allocated to the CDR Activity, i.e. no adjustments are made for the non-biogenic fraction.

However, if the Operator can satisfy all of the Eligibility Criteria EC1 to EC4 in Table 1, they may undertake a mass-balance allocation of emissions to the biogenic fraction in accordance with the calculation methodologies outlined in the CRCF+ Bio-CCS Protocol v1.0. In such cases, project leakage $CO_{2}^{}e_{Leakage}$ emissions (as defined in the CRCF+ GHG Accounting Module) shall not be allocated.

Table 1. Eligibility criteria for mass balance emissions allocation

Emissions associated with energy usage result from the consumption of electricity or fuel.

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

• CO₂ capture process:
  • Electricity used in process operations, including renewable energy, such as:
    • Sorbent/solvent or other regeneration process (electrically heated, electrochemical, or other).
    • Electricity for pumps, motors, drives, etc.
    • Electricity for instrumentation and controls; and
    • Electricity for building operation and management for capture buildings and direct support buildings.
  • Fuel combustion for thermal energy generation (heat/steam) such as:
    • Sorbent/solvent or other regeneration process (thermal); and
    • Heat for capture process buildings and operations.
  • Heat utilization for thermal processes;² and
  • Cryogenic processes for CO₂ purification or liquefaction.
• CO₂ transportation:
  • Electricity or fuel used for operation of a pipeline or similar non-mobile CO₂ transportation process.
• CO₂ storage:
  • Electricity used for operation of any CO₂ conversion processes, such as ex-situ carbonate production and handling;
  • Electricity used for injection operations, including any pumps, compressors (including for compression into supercritical CO₂), or related equipment inside the injection facility gate; and
  • Fuel used for heat generation or other purposes at the conversion or injection sites.

The CRCF+ Bio-CCS Protocol v1.0 and the supplementary CRCF+ GHG Accounting Module v1.0 provide additional guidance on the calculation approach for energy use emissions.

Process emissions associated with the Activity will be calculated by totalling the energy use (thermal and electrical) of all equipment within the Activity boundary. To determine the energy use, the following measurements shall be provided:

Electricity:

• Total electricity used for the CDR process. This may be measured at a single metering point that includes all electricity consumption within the CDR process, or at multiple sub-meters that, in total, account for all electricity use by the CDR process;

Thermal Energy

• Thermal energy used by the CDR process, including steam use, direct combustion of fuels within the CDR process to provide heat, and use of waste heat.

The total thermal energy supplied to the CDR Process shall be measured using the following methods:

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

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

The CRCF+ Bio-CCS Protocol v1.0 gives details of CRCF requirements for the inclusion of transport-related emissions within GHG sources and sinks, including emissions from the transport of biomass and CO₂.

In addition to the specific examples named within the CRCF, the GHG assessment shall assess and include, where material, all other transport emissions within the scope of the CDR Activity (Table 1 of the CRCF+ Bio-CCS Protocol v1.0), including those related to collection and analysis of samples, and staff travel as a direct result of the CDR Activity.

The CRCF+ Bio-CCS Protocol v1.0 and the supplementary CRCF+ GHG Accounting Module v1.0 provide additional guidance on the calculation approach for transportation emissions.

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

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

The CRCF+ Bio-CCS Protocol v1.0 outlines CRCF requirements to consider capital emissions associated with:

• construction and installation of the CO₂ capture facility and geological storage site;
• input emissions from the production and supply of non-energy inputs at capture and storage facilities.

In addition to these requirements, the calculation should also consider capital emissions associated with CO₂ transportation.

Examples of activity-specific materials and equipment that should be considered as part of the capital emission calculation include, but are not limited to:

• Equipment, including:
  • Equipment and infrastructure for processes relating to the wider facility, for example energy generation or product manufacturing.
  • CO₂ capture process:
    • Process equipment, including process units for capture and sorbent regeneration;
    • Sorbent, solvent, or other material handling systems, such as pumps, conveyors, augers, feed bins, and related equipment;
    • Heat transfer equipment;
    • CO₂ purification equipment;
    • CO₂ compression and storage equipment (on-site); and
    • Preparation or mixing equipment for sorbents, solvents, or other materials.
  • CO₂ transportation:
    • Equipment used for transportation of CO₂, including pipelines, and any pumps or compressors.
  • CO₂ storage:
    • Equipment for temporary holding of CO₂ at the injection site; and
    • CO₂ injection equipment, including compressors, pumps, and all wellbore equipment and materials.
  • Monitoring:
    • Monitoring wells and all associated materials (steel casing, concrete, etc.);
    • On-line analyzers, measurement equipment, or other such devices; and
    • Buildings and associated equipment utilized for monitoring purposes(e.g., on-site laboratories).
  • Universal equipment for all processes:
    • Pumps, piping, and related equipment;
    • Storage tanks;
    • All support structures, facilities, and infrastructure, including steel platforms, framing, supports, concrete footings, building structures, offshore rigs where applicable etc.; and
    • All instrumentation, controls, and other process management equipment.
• Consumables, including:
  • Consumables for processes relating to the wider facility, for example energy generation or product manufacturing.
  • CO₂ capture process:
    • Sorbents or solvents, including emissions associated with:
      • Sorbent production including any CO₂ emissions released directly from sorbent production, such as emissions of CO₂ from calcination of limestone; and
      • Proper disposal of used sorbents
    • Heat transfer fluids such as thermal oils or refrigerants.
  • CO₂ storage:
    • Feedstocks or reactants used in the conversion of CO₂ to other products for storage; and
    • Dilutants or additives used to support or improve injection of CO₂ or CO₂-containing product.
  • Monitoring:
    • Gases, reagents, or other materials used for operation of monitoring equipment, analytical testing, calibration of monitoring equipment and on-site analyzers; and
    • Consumable sampling equipment or supplies that are used in significant quantities.
  • Universal consumables for all processes:
    • Gases such as nitrogen used for process operations, instrumentation, purges, or other operations;
    • Water, including full cradle to grave emissions associated with:
      • Delivery of process water (including cooling water), including capital 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.

The CRCF+ GHG Accounting Module sets out further detail on the calculation approach to be followed including life cycle stage, data sources and emission factors.

This glossary provides a side-by-side comparison of terminology used in the EU Carbon Removal Certification Framework (CRCF) and Isometric Protocols and Module.

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

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