Bio-oil Geological Storage
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This Protocol provides the requirements and procedures for the calculation of net CO2e removal from the atmosphere via the conversion of biomass to bio-oil (and co-products) and injection of bio-oil into natural or engineered subsurface features or geologic formations which may include, but are not limited to, reservoirs, saline aquifers, caverns or mines, for long term sequestration of atmospheric CO2. Bio-oil Carbon Capture & Sequestration is considered a subsector of Biomass Carbon Removal and Storage (BiCRS). This Protocol applies to bio-oil sequestration technologies or Projects, which typically consist of activities associated with three sub-processes - biomass growth, biomass conversion, and bio-oil injection and storage.
Bio-oil is a mixture of water, organic acids, aldehydes, ketones, sugars, phenols, and other organic compounds derived from the thermal breakdown of biomass^1. Thermal breakdown of biomass is achieved via thermochemical processes, such as pyrolysis, liquefaction, or gasification, which heat biomass in low- or no- oxygen environments to high temperature (approximately 350°-650°C). Bio-oil is often also referred to as pyrolysis oil or bio-crude.
Bio-oil can have co-products like biochar mixed into it ahead of injection underground. Within this Protocol, we use the words ‘bio-oil’, ‘bio-oil with biochar’ and ‘injectant’ interchangeably.
The Protocol accounts for quantification of the gross amount of CO2 removed via injection of bio-oil into geologic formations, as well as the accounting for all greenhouse gas (GHG) emissions associated with the growth and collection of biomass feedstock, biomass conversion, biomass injection process, all transportation and embodied emissions associated with the process, and emissions associated with leakage. The GHG Statement is considered a cradle-to-grave analysis.
This Protocol is developed to adhere to the requirements of ISO 14064-2: 2019 – Greenhouse Gases – Part 2: Specification with guidance at the project level for quantification, monitoring, and reporting of greenhouse gasemission reductions or removal enhancements. The Protocol ensures:
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 the following:
Additional reference standards that inform the requirements and overall practices incorporated in this Protocol include:
Additional standards, methodologies, and protocols that were reviewed, referenced, or for which attempts to align with or leverage in development of this Protocol include:
This Protocol was developed based on the current state of the art and current publicly available science regarding biomass conversion and bio-oil injection. Because bio-oil injection and storage in geologic formations is a novel carbon dioxide removal (CDR) approach, with limited published literature, the Protocol incorporates requirements that may be more stringent than some current relevant regulations for underground injection, or other protocols related to biomass utilization for CDR.
This approach, notably when specifying requirements for demonstrating bio-oil storagedurability or permanence, will likely be altered in future versions of the Protocol as the stability of bio-oil in geologic formations becomes well demonstrated and documented, reversal risks are proven to be limited or non-existent, and the overall body of knowledge and data regarding all processes, from feedstock supply, to conversion, and to permanent storage is significantly increased.
This Protocol applies to Projects or processes which:
This Protocol applies to Projects and associated operations that meet all of the following project conditions:
Projects that are explicitly NOT eligible include the following:
The Project must consider other environmental and social impacts and the Project Proponent must provide evidence that the Project will do no net environmental or socioeconomic harm, complying with the Isometric Standard.
In addition to that outlined with the Isometric Standard, it must consider all aspects of The Project from feedstock growth through injection and storage. At a minimum the Project Proponent must:
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 the relevant section of the Isometric Standard. The PDD will form the basis for project verification and evaluation in accordance with this Protocol, and must include consideration of processes unique to bio-oil such as:
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 the relevant section of the Isometric Standard.
The Validation and Verification Body (VVB) must consider following requisite components:
The threshold for Materiality, considering the totality of all omissions, errors and mis-statements, is 5%, in accordance with the Isometric Standard.
Verifiers should also verify the documentation of uncertainty of the GHG Statement as required by the relevant section of the Isometric Standard. Qualitative Materiality issues may also be identified and documented, such as4:
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 a minimum, site visits during validation and initial verification to the biomass conversion site and the bio-oil injection site. Validators should, whenever possible, observe operation of the conversion and injection processes to ensure full documentation of process inputs and outputs through visual observation.
A site visit must occur at least once during each project validation. Additional site visits may be required if there are substantial changes to field operations over the course of a project's validation period, or if deemed necessary by Isometric or the VVB.
Verifiers and validators must comply with the requirements defined in the Isometric Standard. In addition, teams shall maintain and demonstrate expertise associated with the specific technologies of interest, including biomass growth, biomass conversion, bio-oil production and geologic storage.
Competency must be demonstrated in accordance with Isometric's VVB policy, for example based on the relevant sectoral scope accreditations in IAF MD 14, or another demonstration of relevant expertise for this protocol and the selected storage module(s).
CDR via bio-oil production and injection is often a result of a multi-step process (such as biomass growth, harvesting, transport, conversion, injection, and storage), with activities in each step managed and operated by a different operator, company, or owner. When there are multiple parties involved in the process (e.g., forestry owner or injection site operator), and to avoid double counting of net CO2e removals, a single Project Proponent must be specified as the sole owner of the Certificates. Contracts must comply with all requirements defined in the Isometric Standard.
The Project Proponent shall be able to demonstrate additionality through compliance with the relevant section of the Isometric Standard. The baseline scenario and counterfactual utilized to assess additionality must be project-specific, and are described Section 7.2 of this Protocol.
Additionality determinations should be reviewed and completed every two years, at a minimum, or whenever project operating conditions change significantly, such as the following:
Any review and change in the determination of additionality shall not affect the availability of Carbon Finance and carbon Certificates for the current or past Crediting Periods, but, if the review indicates the Project has become non-additional, this shall make the Project ineligible for future Certificates.
The uncertainty in the overall estimate of the net CO2e removal as a result of The Project must be accounted for. The total net CO2e removed ([math: CO_2e_{Removal}]) for a specific batch ([math: n]) must be conservatively determined based on the relevant requirements outlined in the Isometric Standard.
Projects must report a list of all input variables used in the net CO2e removal calculation and their uncertainties, including:
The uncertainty information should at least include the minimum and maximum values of each variable that goes into the net CO2e removal calculation. More detailed uncertainty information should be provided if available, as outlined in the relevant section 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 such that a third party can reproduce the results. Input variables may be omitted from an uncertainty analysis if they contribute to a < 1% change in the net CO2e 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 net CO₂e removal will be available to the public through Isometric's platform. That includes:
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 GHG sources, sinks, and reservoirs (SSRs) associated with a bio-oil injection Project.
A cradle-to-graveGHG Statement must be prepared encompassing the GHG emissions relating to the activities outlined within the system boundary.
GHG emissions and removals associated with The Project may be direct emissions from a process or storage system, or indirect emissions from combustion of fuels, electricity generation, or other sources. Emissions must include all GHG SSRs within the system boundary, from the construction or manufacturing of each physical site and associated equipment, closure and disposal of each site and associated equipment, and operation of each process (feedstock collection/harvest, bio-oil production, transportation, injection and monitoring), including embodied emissions of equipment and consumables used in the project. The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities.
Any emissions from sub-processes or process changes that would not have taken place without the CDR Project must be fully considered in the system boundary. Any activity that ultimately leads to the issuance of Certificates should be included in the system boundary. This allows for accurate consideration of additional, incremental emissions induced by the carbon removal process.
The system boundary must include all relevant GHG SSRs controlled and related to The Project, including but not limited to the SSRs set out in Table X. If any GHG SSRs within Table X are deemed not appropriate to include in the system boundary, they may be excluded provided that robust justification and appropriate evidence is provided in the PDD.
Figure 1. Process flow diagram showing system boundary for EW projects
[Image: System boundary diagrams (12)]
Table 1. Scope of activities and GHG SSRs to be included by the removal project
Activity | GHG Source, sink or reservoir | GHG | Scope | Timescale |
|---|---|---|---|---|
Project establishment | Equipment and materials manufacture | All GHGs | Embodied emissions associated with equipment and materials manufacture for project establishment (lifecycle modules](#def) A1-3). To include product manufacture emissions for equipment, buildings, infrastructure and temporary structures. | Before project operations start - must be accounted for in the first Reporting Period or amortized in line with allocation rules (See Section 8.5.1) |
Equipment and materials transport to site | All GHGs | Transport emissions associated with transporting materials and equipment to the project site(s) (lifecycle module A4). | ||
Construction and installation | All GHGs | Emissions related to construction and installation of the project site(s) (lifecycle module A5). To include energy use for construction, installation and groundworks, as well as waste processing activities and emissions associated with land use change. | ||
Initial surveys and feasibility studies | All GHGs | Any embodied, energy and transport emissions associated with surveys or feasibility studies required for establishment of the project site. | ||
Misc. | All GHGs | Any SSRs not captured by categories above, for example staff transport. | ||
Operations | Biomass Feedstock Sourcing | All GHGs | Any embodied, energy and transport emissions associated with biomass cultivation and harvesting. | Over each Reporting Period - must be accounted for in the relevant Reporting Period (See Section 8.5.2) |
Biomass feedstock transport | All GHGs | Transport of biomass including to biomass processing site and all other transport of biomass ahead of bio-oil production. | ||
Biomass feedstock processing | All GHGs | Any embodied, energy and transport emissions associated with biomass feedstock processing. | ||
Pyrolysis or other process | All GHGs | Emissions associated with pyrolysis (or other processes) including:
| ||
Direct emissions | All GHGs | Direct emissions released during pyrolysis. See Section 8.3.6 for calculation details. | ||
Bio-oil processing | All GHGs | Emissions associated with bio-oil processing and characterization including:
| ||
Bio-oil storage | All GHGs | Emissions associated with bio-oil storage including:
| ||
Bio-oil transport | All GHGs | Emissions related to all transport of bio-oil, including to bio-oil processing site, to the bio-oil storage site, and to injection site. | ||
Bio-oil injection | All GHGs | Emissions associated with bio-oil injection including:
| ||
CO₂ Stored | CO₂ | The gross amount of CO₂ removed and durably stored from a bio-oil project over a Reporting Period. | ||
Sampling required for MRV | All GHGs | Any embodied, energy and transport emissions associated with sampling for MRV purposes, including transportation to collect samples, shipping of samples for laboratory analysis and sample processing. | ||
Staff travel | All GHGs | Flight, car, train or other travel required for the project operations, including contractors and suppliers required on site. | ||
Surveys | All GHGs | Equipment, energy use and transport associated with surveys e.g. ecological surveys. | ||
Misc. | All GHGs | Any SSRs not captured by categories above. | ||
End-of-life | End-of-life of project facilities | All GHGs | Anticipated end-of-life emissions (lifecycle modules C1-4). To include deconstruction and disposal of the project site(s), equipment, vehicles, buildings or infrastructure. | After Reporting Period - must be accounted for in the first Reporting Period or amortized in line with allocation rules (See Section 8.5.3) |
Misc. | All GHGs | Any emissions SSRs not captured by categories above. |
Miscellaneous GHG emissions are those that cannot be categorized by the GHG SSR categories provided in Table 1. The Project Proponent is responsible for identifying all sources of emissions directly or indirectly related to project activities and must report any outside of the SSR categories identified as miscellaneous emissions.
Emissions associated with The Project's impact on activities that fall outside of the system boundary of The Project must also be considered. This is covered under Leakage in Section 8.5.4.
In some instances, the project activities may be integrated into existing activities. Activities that were already occurring, and would continue to occur in the absence of The Project, may be omitted from the system boundary of the GHG accounting if evidence of this is provided.
In line with the GHG Accounting Module v1.1, the Project must:
The baseline scenario for bio-oil projects assumes the activities associated with the bio-oil project do not take place and any infrastructure is not built.
The counterfactual is the CO2 stored in the biomass feedstock that would have remained durably stored in the biomass in the absence of The Project. This is known as ineligible biomass, given that the CO2 stored would have remained stored in the biomass in the absence of the CDR Project and is therefore not eligible to count towards net CDR. The Biomass Feedstock Accounting Module v1.34 sets out requirements for establishing ineligible biomass as part of the Counterfactual Storage Eligibility criteria. The Biomass Feedstock Accounting Module v1.34 includes details for quantification of [math: CO_2e_{Counterfactual}].
See Section 3 of the Biomass Feedstock Accounting Module for requirements.
The biomass pyrolysis process can be modeled as operating on a batch basis, consisting of a ‘Production Batch’, [math: p], which typically consists of utilizing a single type of biomass feedstock, often of a single source of origin, converting the biomass to bio-oil via pyrolysis, and storing and transporting that bio-oil to an injection site. The unique characteristics of the biomass used, the bio-oil conversion process, the produced bio-oil characteristics, transportation distances, and storage site characteristics will be consistent for each Production Batch.
An ‘Injection Batch’, [math: n], is a single injection activity where a quantity of bio-oil is injected into an approved underground storage site. The Injection Batch may consist of a portion of a Production Batch, a full single Production Batch, or a blend of multiple Production Batches, which is injected for durable storage.
Emissions that occur relating to an Injection Batch, [math: n], must be included in the reporting of emissions associated with that batch and may not be allocated across multiple batches. Allocation across multiple batches must be agreed with Isometric on a case by case basis.
The approach for emissions calculations here is based on Injection Batches and the specific calculation of net CO2e removal for each Injection Batch. The following sections outline the process for calculating the net CO2e removed for each specific Injection Batch of biomass processed and associated bio-oil injection, defined as a Removal.
The Reporting Period for a bio-oil project represents an interval of time over which removals are calculated and reported for verification. When total net CO2e removals must be calculated for a Reporting Period, for example during submission of Claimed Removals in a GHG statement, it is calculated as the sum of removals during the Reporting Period:
[math: CO_2e_{Removal,\ RP} =\sum_{1}^{n}\ CO_2e_{Removal,\ n}]
(Equation 1)
Where
Net CO2e removal for bio-oil project can be calculated as follows. Note that the calculation is completed for a discrete batch, [math: n], of bio-oil that is injected (‘Injection Batch’). The final net CO2e quantification must be conservatively determined, giving high confidence that at least the estimated amount of CO2e was removed.
[math: CO_2e_{Removal,\ n} = CO_2e_{Stored,\ n}\ –\ CO_2e_{Counterfactual,\ n}\ - \\ CO_2e_{ Emissions,\ n}]
(Equation 2)
Where
It should be noted that any potential reversals of CO2 storage in the final storage location occur after Certificate have been issued so are not included in this equation. See the Isometric Standard for further information. Risk of reversal information is given in Appendix 2: Risk of Reversal Questionnaire, with further information provided within the relevant storage module.
[math: CO_2e_{Stored}] represents the amount of CO2 (stored as organic carbon, C) that is injected and stored in the geologic or engineered storage formation. This is the gross amount stored for each batch injection and does not account for spillage nor reversals of storage from the storage formation.
The total amount of CO2 contained in the injectant can be calculated as follows.
Where all bio-oil production batches are blended prior to injection:
[math: CO_2e_{Stored,\ n} = \frac{C_{Bio-oil,\ n}\cdot m_{Inj,\ n}}{C_{CO_{2}}}]
(Equation 3)
Where bio-oil production batches are not blended prior to injection:
[math: CO_2e_{Stored,\ n} = \sum_{p=1}^{k} \bigg(\frac{C_{Bio-oil,\ p}\cdot m_{Inj,\ p}}{C_{CO_{2}}} \bigg)]
(Equation 4)
Where:
Calculation of [math: CO_2e_{Stored}] requires two primary measurements:
In order to determine [math: C_{Bio -oil}], the %wt of C in the bio-oil injectant for either a blended bio-oil in Injection Batch [math: n], or for individual Production Batches [math: p], is determined via the analysis of samples of bio-oil injectant for total C content.
The following test method should be used where possible, and must be used for bio-oils or blends with vapor pressures higher than 3 psi5:
Where this is not possible, other acceptable test methods include:
A minimum of one sample per Injection Batch (for blended injections) or one per Production Batch (for non-blended injections) of bio-oil must be collected and analyzed. Samples shall be from a well mixed and representative aliquot of the bio-oil as injected, insuring that solids are blended in the sample and representative of the amount in the injectant.
Analysis must be completed by a qualified laboratory, as evidenced by accreditation to ISO 17025 or equivalent standards for laboratory quality management for the specific test method (ASTM D5291).
Laboratories shall complete standard quality assurance procedures on a schedule in accordance with their quality management plans and accreditation requirements to include:
This Protocol provides two alternative methods for how often C content must be measured and quantified. The first method (A) involves measuring every batch, the second method (B) involves only sampling some batches, and conservatively estimating the C content of unsampled batches.
Method A: Measure every Batch
The C content of every Injection Batch must be ascertained through direct measurement, either by:
For the acceptable minimum number of samples to take per sampled Batch, see Minimum number of samples per Batch below. If multiple samples are taken per Batch, the average C content of these samples must be used.
Method B: Sampling a Production Process
For a given Production Process of a feedstock, samples must be taken directly for at least 30 Production Batches, to ensure there is enough data to estimate C content for future Production Batches with appropriate statistical significance. Until this threshold is reached, Method A must be used.
Subsequently, samples must be taken at least every 10 Production Batches.
For the acceptable minimum number of samples to take per Batch, see Minimum number of samples per Batch below.
For batches which are not sampled, C content must be conservatively estimated, as follows:
[math: C_{Bio-oil} = \mu_{CC} - \sigma_{\overline{CC}}]
(Equation 5)
[math: \sigma_{\overline{CC}} = \frac{\sigma_{CC}}{\sqrt{n_{samples}}}]
(Equation 6)
where:
Eligible samples are those taken in the previous 6 months before a specific Production Batch was produced. Older samples may not be used.
Additionally, batches must be subject to random sampling, to alleviate the risk of any given batch containing a substance with a substantially different C content.
A 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 month, on average. Once contacted, the Project Proponent must sample the C content of the subsequent batches processed.
If the Project Proponent is unable to carry this random sampling out on 3 occasions within a 6 month period, or within a 6 month period more than 3 measurements are below 3 SD from the mean, this will trigger a Project review by Isometric.
If there is a significant change to a Production Process for a feedstock, which is likely to alter the average C content of the feedstock, or if significant deviations in carbon content are detected, the feedstock should be considered as a new Production Process. This means that sampling must be restarted, with all prior samples no longer able to be used for estimating C content.
Minimum number of samples per Batch
For all measurements taken, samples must be from a well mixed and representative aliquot of the injectant. To account for the possibility of variation within a single Production Batch (for example within a large container of the injectant), either of the following approaches must be adopted:
Process for handling C content measurement outliers
For a given Production Process, an Outlier is defined as any individual sample which lies more than 3 standard deviations, [math: \sigma_{CC}], above or below the mean. To minimize the potential overall impact of outlier measurements, all C content measurement outliers must be handled via the applying the technique of "winsorization”, as follows.
For a given measurement, [math: m], the winsorized measurement [math: m_w] is defined as follows:
The winsorized measurement, [math: m_w], must be used for the determination of carbon content.
This winsorization process must only be applied once a minimum number of 30 measurements have been taken, to ensure statistical significance.
The Project Proponent must monitor occurrences of outliers, and investigate if significantly more than the statistically expected number occurs, as it may be indicative of a systematic issue. This may be checked at verification, at the discretion of the verifying VVB.
The mass of injectant, [math: m_{Inj}], is measured via determination of weight of delivered bio-oil to the injection site using a calibrated scale. The total mass injected may be determined by the difference in bio-oil delivery truck weight measured upon arrival at the injection facility and at departure, after offloading of bio-oil, either into storage or directly to injection.
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 specifications7, and scale testing and calibration must be performed by a state certified entity.
The total mass injected may also be determined by other methods, such as use of a calibrated flow meter and density measurement, or use of calibrated on site weigh scales for smaller containers, where such methods are viable and justified. Note that, due to typical viscosity of bio-oil, the use of flow meters is not often viable and can result in poor data quality.
The Project Proponent must maintain the following records as evidence of CO2 removal in injected bio-oil:
Records of all C analyses and injection masses (e.g. weigh scale tickets) must be maintained by the injection facility and provided for verification purposes for a period of five years after the end of the monitoring period.
Although limited and of small quantity, injection processes should be monitored to ensure that any process upsets or equipment failures and resulting spills of bio-oil are monitored, documented, quantified, and accounted for in the GHG Statement of the project batch. For each batch, where a process upset results in loss of bio-oil, that amount must be deducted from the delivered amount of bio-oil based on delivery weigh tickets. Such amounts must be allocated directly to the specific injection batch of bio-oil.
[/R-QQ8W-0]The calculation of [math: CO_2e_{Counterfactual,\ n}], is determined by the requirements of the Biomass Feedstock Accounting Module.
See Section 3 of the Biomass Feedstock Accounting Module
[math: CO_2e_{Emissions,\ n}] is the total quantity of GHG emissions from operations and allocated embodied emissions for a batch [math: n]. This can be calculated as:
[math: {CO}_{2}^{}e_{Emissions,\ n}^{}\ = \ {CO}_{2}^{}e_{Establishment,\ n}^{}\ + \ {CO}_{2}^{}e_{Operations,\ n}^{} + \ {CO}_{2}^{}e_{End-of-Life,\ n}^{}+ \ {CO}_{2}^{}e_{Leakage,\ n}^{}]
(Equation 7)
Where
The following sections provide an overview for each variable.
GHG emissions associated with [math: CO_{2}e_{Establishment,\ n}] should include all historic emissions incurred as a result of project establishment, including but not limited to the SSRs set out in Table 1.
Project establishment emissions occur from the point of project inception through to before the first removal activity takes place. GHG emissions associated with project establishment may be amortized over the anticipated project lifetime, or per output of product. Rules on amortization are outlined in Section 7 of the GHG Accounting Module.
See Section 7 of the GHG Accounting Module
GHG emissions associated with [math: CO_{2}e_{Operations,\ n}] should include all emissions associated with operational activities including but not limited to the SSRs set out in Table 1.
[math: CO_{2}e_{Operations,\ n}] emissions must be attributed to the batch [math: n] to which they are associated. Allocation may be permitted in certain instances, on a case by case basis, in agreement with Isometric.
[math: CO_{2}e_{End-of-Life,\ n}] includes all emissions associated with activities that are anticipated to occur after the Crediting Period until the end of the Project Commitment Period. This includes activities related to ongoing monitoring for Reversals.
[math: CO_{2}e_{End-of-Life,\ n}] must be estimated upfront and allocated in the same way as set out for calculation of [math: CO_{2}e_{Establishment,\ n}].
Given the uncertain nature of [math: CO_{2}e_{End-of-Life,\ n}] emissions, assumptions must be revisited at each Reporting Period and any necessary adjustments made.
[math: 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 bio-oil project, replacement emissions must be considered as a minimum. Calculations required for replacement emissions associated with market leakage are set out in the Biomass Feedstock Accounting Module.
In line with the Sustainability Criteria set out in the Biomass Feedstock Accounting Module v1.34, projects which would lead to ecological leakage associated with land use change are not eligible under this Protocol.
See Section 4 of the Biomass Feedstock Accounting Module
GHG emissions accounting must be undertaken in alignment with the GHG Accounting Module v1.1, which ensures a consistently rigorous standard in how GHG emissions are quantified and reported between different CDR Projects and approaches. This includes:
Refer to GHG Accounting Module for emissions accounting guidelines.
The Energy Use Accounting Module v1.3 provides requirements on how energy-related emissions must be calculated for The Project 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 emission factors.
Energy emissions are those related to electricity or fuel usage. Examples of electricity usage may include, but are not limited to:
Examples of fuel consumption may include, but are not limited to:
Refer to the Energy Use Accounting module for guidance on fuel and energy emissions accounting.
The GHG Accounting Module v1.1 provides requirements on how transportation and embodied emissions must be calculated for The Project so that they can be subtracted in the net CO₂e removal calculation.
Embodied emissions are those related to the life cycle impact of equipment and consumables. They may include, but are not limited to:
Transportation emissions are those related to transportation of products and equipment. They may include, but are not limited to:
Refer to Section 4.1 and Section 4.2 of the GHG Accounting Module for guidance on embodied and transportation emissions calculations.
The biomass pyrolysis process may result in the production of co-products, such as biochar, pyrolysis gas (bio-gas), electricity and heat.
Projects must follow the co-product allocation procedures described in Section 6.1 of the GHG Accounting Module v1.1. For projects where the CDR product(s) and co-products have a measurable energy content, the optional procedure outlined in Section 8.5.5.1.1 may be applied instead of the Procedures outlined in Section 6.1 of the GHG Accounting Module v1.1.
Emissions allocation may be undertaken based on energy content for shared processes in instances where all co-products, including CDR products, have a measurable energy content which can be expressed in Megajoules (MJ). Shared processes are defined as processes for which the CDR product and all co-products are mutually dependent on. Where this is not the case for all co-products, no allocation should be made based on energy content. In this section Net Calorific Value is defined as the amount of energy released by complete combustion, assuming the water vapor produced during combustion is not condensed and used.
Equation 8 sets out the calculation procedure to be followed to apply emissions allocation based on energy content. When this procedure is followed, the term [math: CO_2e_{Emissions,RP}] in Equation 7 in Section 8.5 should be calculated based on Equation 8 for any shared processes.
[math: CO_2e_{Emissions,RP} = (F_{Allocation,RP} \;*\; ( CO_2e_{Establishment,RP} \;+ \;CO_2e_{Operations,RP} \;+ \;CO_2e_{End-Of-Life,RP})) \;+ \;CO_2e_{Leakage,RP}]
(Equation 8)
Where:
[math: CO_2e_{Establishment,RP}], [math: CO_2e_{Operations,RP}], [math: CO_2e_{End-Of-Life,RP}] and [math: CO_2e_{Leakage,RP}] are calculated as per the relevant sections of this Protocol.
[math: F_{Allocation}] is the fraction of emissions assigned to the CDR product, represented as:
[math: F_{Allocation} = \frac {MJ_{Output, CDR}}{\qquad \sum_{p=1}^n MJ_{Output, p}}]
(Equation 9)
Where:
[math: MJ_{Output, CDR}] is the energy content of the CDR product, equal to the Net Calorific Value, expressed in MJ/kg.
[math: MJ_{Output}] is the energy content of a specific output, expressed in MJ. The sum of outputs for all co-products must be considered in Equation 9:
Direct emissions of tailgas as part of a pyrolysis process ([math: CO_2e_{Tailgas,\ n}]) may occur when pyrolysis gasses are emitted to the atmosphere, are combusted within the process or pyrolyzer to provide thermal energy for the process, or are combusted or oxidized in an emissions control process such as a flare or thermal oxidizer.
Emissions are calculated as follows:
[math: CO_2e_{Tailgas,\ p}\ =\\ m_{Tailgas} \cdot C_{Tailgas,\ CH_4}\ \cdot GWP_{CH_4}\ \cdot t_p]
(Equation 10)
Where:
Quantification of [math: CO_2e_{Tailgas}] requires two primary measurements, the measurement of tail gas flow and the analysis of gas for CH4 content. CO2 content is not included as part of the [math: CO_2e_{Tailgas}] emissions asbecause it is biogenic, and any counterfactually stored carbon is already deducted through [math: CO_2e_{Counterfactual}] under the Biomass Feedstock Accounting Module v1.34 requires that only biomass which would have decayed within 15 years is used. Therefore the immediate emissions of CO2 due to pyrolysis are not discounted against the net CO2e removal due to the similarity of time horizons between these emissions and the counterfactual storage.
Tailgas flow rate, [math: m_{Tailgas}] can be determined by various acceptable methods, including:
The concentration of CH4 in the tail gas must be measured directly via one of the following methods:
The Project Proponent must maintain the following records as evidence supporting calculation of emissions from the biomass conversion process, for a minimum of five years after the end of the monitoring period:
This Protocol provides two options for durable storage of bio-oil. The Project Proponent can choose from available options when submitting their Project for verification.
Durability and monitoring requirements for storage in permeable reservoirs.
Durability and monitoring requirements for storage in salt caverns.
Isometric would like to thank following contributors to this Protocol and relevant Modules:
Isometric would like to thank following reviewers of this Protocol and relevant Modules:
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:
This risk assessment identifies the pathway specific risk factors relevant to a carbon removal project. The relevant risk factors identified as part of a risk assessment are included in the monitoring plan requirements for the project, with details included in the Project Design Document. Project specific risk factors inform the required duration of monitoring along with the monitoring requirements set out in the Protocol and the requirements set out in the Monitoring Section of the Isometric Standard.
Projects using this Protocol have the option of a number of storage modules. The typical buffer pool contributions and the rationale are indicated in the relevant storage module: typically, salt cavern storage is considered Very Low Risk Level (leading to a 1% buffer pool), and permeable reservoir storage is considered Low Risk Level (leading to a 5% buffer pool).
The risk score, as determined by the Risk of Reversal Questionnaire, will determine a project’s buffer pool contribution. Projects must re-assess their reversal risk at the renewal of each Crediting Period, or if monitoring identifies a reversal-related risk, or if an actual reversal event takes place.
The Risk of Reversal Questionnaire questions that pertain to this protocol, drawn from the programme-level Risk of Reversal Questionnaire defined in the Isometric Standard, include the following:
/# in Isometric Standard Questionnaire | Question | If answered “Yes” | If answered “No” |
|---|---|---|---|
1 | Is a reversal directly observable with a physical or chemical measurement as opposed to a modeled result? | Proceed to questions 2-10 | Proceed to questions 8-10 |
2 | Is the carbon being stored in an impermeable geologic system? (e.g., salt cavern) | Proceed to questions 8-10 | Add 1 to Risk Score and proceed to questions 3-10 |
3 | Is the carbon being stored organic? | Add 1 to Risk Score | |
4 | Are conditions for methane production present (anaerobic conditions, lignin content)? | Add 1 to Risk Score | |
5 | Does this approach have a material risk of reversal due to natural disasters including, but not limited to, floods, storms, earthquakes, fires, etc.? | Add 1 to Risk Score | |
6 | Does this approach have a material risk of reversal due to human-induced events from outside actors, such as change in farming practices, change in ownership and management of project sites, or similar? | Add up to 2 to Risk Score | |
7 | **Applicable only for subsurface storage**: Is the carbon being stored with trapping mechanisms preventing reversals? (e.g., multiple confining layers, CO₂ dissolves or solidifies) | Minus 1 to Risk Score (unless 0) | |
8 | Is there 10+ years of monitoring and/or lab data demonstrating low project risk? | Minus up to 2 to Risk Score | |
9 | Does this pathway have a documented history of reversals in excess of proposed buffer pool size? | Add 2 to Risk Score | |
10 | Is there one or more project-specific factors that merit a high risk level? | Add up to 2 to Risk Score |
Note the Risk Score at any step cannot be negative.
Risk Score Categories:
Project specific risk factors will depend on the form of carbon being stored (i.e., organic vs. inorganic), the method of storage (e.g., mineralization, encapsulation), the location of carbon storage (e.g., subsurface, ocean), and the proximity of that carbon to potential agents of reversal.
For projects with carbon storage as organic carbon, the presence the following risk factors must be reflected in the risk score corresponding to question 10:
For projects with any form of subsurface carbon storage, the presence of the following risk factors must be reflected in the risk score corresponding to question 10:
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Sustainable sourcing may be demonstrated via certification or demonstrated compliance with programs such as the Forest Stewardship Council (https://fsc.org/en), High Conservation Value Network (https://www.hcvnetwork.org/), Sustainable Biomass Program (https://sbp-cert.org/), Roundtable for Sustainable Biomass (https://rsb.org/the-rsb-standard/about-the-rsb-standard/), European Union Renewable Energy Directive (RED II), Sustainable Forestry Initiative, or other similar biomass sustainability protocols, standards, and compliance methods. ↩
Note that other well classes may be utilized, such as Class II wells, if site specific UIC well permits identify bio-oil as an acceptable injectant. However, Class II wells may not be utilized if the wells are also used for enhanced hydrocarbon recovery (EHR or EHR+) activities. ↩
For Class V wells, the well must be permitted and not ‘authorized by rule’, and must consider the specific emplacement and durable storage of bio-oil in the geologic reservoir. As of writing, the utilization of Class V wells should be limited to wells operating under the Other / Experimental category of Class V wells or other appropriate well type as approved by the UIC permitting authority. ↩
https://www.nrel.gov/docs/fy22osti/80967.pdf↩↩2
https://www.nist.gov/pml/owm/publications/nist-handbooks/handbook-44-current-edition↩
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. ↩