Bio-oil Geological Storage

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 gas emission reductions or removal enhancements. 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 removals.
• Consistent system boundaries and calculations are utilized to quantify net CO₂e removal for bio-oil injection projects.
• Requirements are met to ensure the CO₂ removals are additional.
• 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 the following:

• Isometric Standard
• ISO 14064-2: 2019 – Greenhouse Gases – Part 2: Specification with guidance at the project level for quantification, monitoring, and reporting of greenhouse gas emission reductions or removal enhancements

Additional reference standards that inform the requirements and overall practices incorporated in this Protocol include:

• ISO 14064-3: 2019 – Greenhouse Gases – Part 3: Specification with Guidance for the verification and validation of greenhouse gas statements
• ISO 14040: 2006 - Environmental Management - life cycle Assessment - Principles & Framework
• ISO 14044: 2006 - Environmental Management - life cycle Assessment - Requirements & Guidelines

Additional standards, methodologies, and protocols that were reviewed, referenced, or for which attempts to align with or leverage in development of this Protocol include:

• Bio-oil Sequestration Prototype Protocol for Measurement, Reporting, & Verification. Carbon Direct / EcoEngineers, 2022
• Carbon Capture & Sequestration Protocol under the Low Carbon Fuel Standard. California Air Resources Board (CARB). August, 2018

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 storage durability 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:

• Utilize eligible feedstocks in accordance with the framework set out in the Biomass Feedstock Accounting Module v1.3.
• Convert the biomass to bio-oil via pyrolysis or similar processes or utilize bio-oil produced by a third-party supplier.
• Inject the bio-oil into natural or engineered geologic formations for long duration storage purposes via an underground injection well.

This Protocol applies to Projects and associated operations that meet all of the following project conditions:

• the Project provides a net-negative CO₂e impact (net CO₂e removal) as calculated in the GHG Statement, in compliance with Section 8;
• the biomass feedstock utilized is sustainably sourced¹;
• the Project does no net harm to the environment and society;
• the Project is considered additional, in accordance with the requirements of Section 6.4;
• the Project provides long duration storage (>1000 yr estimated) of carbon in geologic formations;
• the geologic storage site is located in the US or a region with similar geologic storage permitting requirements;
• the geologic storage site is properly permitted and has a current relevant UIC well permit ². The site must be operated in compliance with current permits issued by the U.S. EPA, U.S. States or an equivalent permitting regime for underground injection control wells; and specifically identify bio-oil or an equivalent type of injectant as acceptable injectants under the permit ³.

Projects that are explicitly NOT eligible include the following:

• Projects that utilize bio-oil as part of enhanced hydrocarbon recovery (EHR or EHR+);
• Projects that utilize biomass that doesn't meet the eligibility criteria detailed in Biomass Feedstock Accounting Module v1.3.

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:

1. document activities conducted under The Project which would require it to obtain environmental permits and provide a listing of all permits or construction approvals received or applied for and their current status and compliance history. This may include, but is not limited to, activities under the Resource Conservation & Recovery Act (RCRA), the U.S. EPA Underground Injection Control (UIC) program, the National Pollutant Discharge Elimination System (NPDES) program under the Clean Water Act (CWA), the Prevention of Significant Deterioration (PSD) program under the Clean Air Act (CAA), and other relevant environmental permits such as federal, state, county, or city permits for air, water or waste discharges;
2. document activities that would require the Project Proponent to obtain any drilling permits, access agreements, or any encroachment permits under county or city guidelines, or any federal, state, or local air, water, or restricted land use operating permits;
3. when agricultural residues are used, provide documentation of characterization of biomass in accordance with the Biomass Feedstock Accounting Module v1.3 to demonstrate impact on carbon and nutrient (nitrogen, phosphorus, potassium) removal;
4. provide documentation demonstrating whether the bio-oil is non-hazardous or hazardous, based on U.S. EPA RCRA requirements and testing completed by an accredited laboratory in accordance with U.S. EPA methods recommended in the Test Methods for Evaluating Solid Waste: Physical/Chemical Methods Compendium (SW-846)⁴ or equivalent, unless exempted by permit rule or standard. If the bio-oil is classified as hazardous:

• evidence must be provided that all protocols for hazardous substance handling and management are being followed;
• injection well permits must allow for hazardous waste injection and evidence that the permit conditions are being followed, must be provided;
• containment within the targeted storage reservoir must be ensured and monitored, and all evidence provided.

5. demonstrate a risk assessment and mitigation plan for safeguarding working conditions, especially when it comes to safe handling and transportation of biomass feedstocks as well as workers operating the storage facility.

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:

• location information for biomass production, biomass conversion, bio-oil injection, and geologic storage formation
• conditions of biomass use prior to project initiation
• details on technologies, products, and services relevant to biomass conversion processes, including production rates and volumes

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:

1. Validate that feedstock adheres to the requirements listed in the Biomass Feedstock Accounting Module v1.3.
2. Verify that storage sites adhere to the requirements listed in the relevant storage module.
3. Verify that the quantification approach and monitoring plan adheres to requirements of Section 8, including demonstration of required records.
4. Verify that the Environmental & Social Safeguards outlined in Section 5 are met.
5. 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 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:

• control issues that erode the verifier’s confidence in the reported data
• poorly managed documented information
• difficulty in locating requested information
• 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 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 Credits. 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:

• 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:
  • increased tipping fees for waste feedstocks
  • 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 shall not affect the availability of Carbon Finance and carbon Credits 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 credits⁵.

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 ($CO_2e_{Removal}$) for a specific batch ($n$) 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:

• emission factors utilized, as published in public and other databases used
• values of measured parameters from process instrumentation, such as truck weights from weigh scales, flow rates from flow meters, electricity usage from utility power meters, and other similar equipment
• laboratory analyses, including analysis of carbon content of injected bio-oil

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:

• Project Design Document
• GHG Statement
• Measurements taken and supporting documentation, such as calibration certificates
• Emission factors used
• Scientific literature used

The Project Proponent can request certain information to be restricted (only available to authorized Buyers, the Registry and VVB) where it is subject to confidentiality. This includes emissions factors from licensed databases. However, all other numerical data produced or used as part of the quantification of net CO₂e removal will be made available.

The scope of this Protocol includes GHG sources, sinks, and reservoirs (SSRs) associated with a bio-oil injection Project.

A cradle-to-grave GHG Statement must be prepared encompassing the GHG emissions relating to the activities outlined within the system boundary.

GHG emissions and removals associated with The Project may be 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 Credits 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

Table 1. Scope of activities and GHG SSRs to be included by the removal project

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:

• Consider all GHGs associated with SSRs, in alignment with the United States Environmental Protection Agency’s definition of GHGs, which includes: carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂0) and fluorinated gasses such as hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF₆) and nitrogen trifluoride (NF₃). For CO₂ stored, only CO₂ shall be included as part of the quantification. For all other activities all GHGs must be considered. For example, the release of CO₂, CH₄, and N₂O is expected during diesel consumption;
• Quantify emissions in tonnes CO₂ equivalent (t CO₂e) using the 100-year Global Warming Potential (GWP) for the GHG of interest, based on the most recent volume of the IPCC Assessment Report (currently the Sixth Assessment Report); and
• Consider materiality of SSRs in line with Isometric requirements.

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 crediting. The Biomass Feedstock Accounting Module v1.3 sets out requirements for establishing ineligible biomass as part of the Counterfactual Storage Eligibility criteria. The Biomass Feedstock Accounting Module v1.3 includes details for quantification of $CO_2e_{Counterfactual}$.

The biomass pyrolysis process can be modeled as operating on a batch basis, consisting of a ‘Production Batch’, $p$, 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’, $n$, 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, $n$, 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:

$$CO_2e_{Removal,\ RP} =\sum_{1}^{n}\ CO_2e_{Removal,\ n}$$

(Equation 1)

Where

• $CO_2e_{Removal,\ RP}$= the total net CO₂e removal for Reporting Period $RP$, in tonnes of CO₂e
• $CO_2e_{Removal,\ n}$ = the total net CO₂e removal for Injection Batch $n$, occurring in Reporting Period $RP$, in tonnes of CO₂e, see Section 8.2, Equation 2

Net CO₂e removal for bio-oil project can be calculated as follows. Note that the calculation is completed for a discrete batch, $n$, 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.

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

(Equation 2)

Where

• $CO_2e_{Stored,\ n}$ = the total CO₂ removed from the atmosphere and durably stored as biogenic carbon for batch n, in tonnes of CO₂e, see Section 8.3
• $CO_2e_{Counterfactual,\ n}$ = the total counterfactual CO₂ removed from the atmosphere and durably stored as biogenic carbon in the absence of the project, for batch n, in tonnes of CO₂e, see Section 8.4
• $CO_2e_{Emissions,\ n}$ = the total GHG emissions for batch $n$, in tonnes of CO₂e, see Section 8.5

It should be noted that any potential reversals of CO₂ storage in the final storage location occur after Credits 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.

$CO_2e_{Stored}$ 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:

$$CO_2e_{Stored,\ n} = \frac{C_{Bio-oil,\ n}\cdot m_{Inj,\ n}}{C_{CO_{2}}}$$

(Equation 3)

Where bio-oil production batches are not blended prior to injection:

$$CO_2e_{Stored,\ n} = \sum_{p=1}^{k} \bigg(\frac{C_{Bio-oil,\ p}\cdot m_{Inj,\ p}}{C_{CO_{2}}} \bigg)$$

(Equation 4)

Where:

• $n$ = Injection batch
• $p$ = Production batch
• $k$ = number of Production batches, $p$, blended in the Injection batch, $n$
• $CO_2e_{Stored,\ n}$= the total CO₂ removed for batch $n$, in tonnes of CO₂e
• $C_{Bio -oil,\ n (p)}$ = the concentration as weight percent (%wt) of C in the bio-oil injectant injected for Injection Batch $n$ OR for each production batch $p$ included in Injection Batch $n$
• $m_{Inj,\ n (p)}$= the total mass of injectant emplaced via injection (tonne) for Injection Batch $n$ OR for each production batch $p$ included in Injection Batch $n$
• $C_{CO_{2}}$ = the content of C in CO₂ (as a mass percent)

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

• $C_{Bio -oil}$ - %wt of C in the bio-oil injectant
• $m_{Inj}$ - total mass of injectant

In order to determine $C_{Bio -oil}$, the %wt of C in the bio-oil injectant for either a blended bio-oil in Injection Batch $n$, or for individual Production Batches $p$, 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 psi⁶:

• NREL Laboratory Analysis Procedure for Determination of Carbon, Hydrogen, and Nitrogen in Bio-oils⁷ should be used where possible, and must be used for bio-oils or blends with vapor pressures higher than 3 psi⁶

Where this is not possible, other acceptable test methods include:

• ASTM D5291: Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants
• ASTM D5373: Standard Test Methods for Determination of Carbon, Hydrogen and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke
• Alternative methods or analytical equipment which determine total carbon content may be utilized if justified and documented to be equivalent to ASTM D5291.

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:

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

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:

1. Sampling the Injection Batch (which may be blended, or non-blended);
2. Sampling all constituent Production Batches which comprise the Injection Batch, and calculating the C content of the Injection Batch through a linear weighted combination of the C contents of these Production Batches, as given in Equation 3.

• Note that in the case of an unblended Injection Batch, the Injection Batch originates from only a single Production Batch, by definition, and no calculation is required.

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:

$$C_{Bio-oil} = \mu_{CC} - \sigma_{\overline{CC}}$$

(Equation 5)

$$\sigma_{\overline{CC}} = \frac{\sigma_{CC}}{\sqrt{n_{samples}}}$$

(Equation 6)

where:

• $\sigma_{\overline{CC}}$ is the standard error of the mean of C content, across all eligible samples for this Production Process
• $\sigma_{CC}$ is the standard deviation of C content, across all eligible samples for this Production Process
• $n_{samples}$ is the number of eligible samples for this Production Process
• $\mu_{CC}$ is the mean C content of all eligible samples for this Production Process

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:

1. A minimum of 3 samples must be taken for each measured Production Batch.
2. Justification and evidence must be provided to demonstrate that the “within batch” variation is likely to be minimal. For example, this could be justified due to the physical details of the Production Process used, or alternatively by providing data examining the “within batch” C content variation.

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, $\sigma_{CC}$, 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, $m$, the winsorized measurement $m_w$ is defined as follows:

• For a measurement $m$ where $m > \mu + 3\sigma_{CC}$, $m_w = \mu + 3\sigma_{CC}$
• For a measurement $m$ where $m < \mu - 3\sigma_{CC}$, $m_w = \mu - 3\sigma_{CC}$

The winsorized measurement, $m_w$, 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, $m_{Inj}$, 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 specifications⁸, 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:

• weigh scale tickets for each delivery of bio-oil (arrival and departure weights) or other equivalent records
• analytical results for each ASTM D5291 analysis for C content of bio-oil from each batch as required
• Documentation of any spills during injection operations and estimates of quantity released

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.

The calculation of $CO_2e_{Counterfactual,\ n}$, is determined by the requirements of the Biomass Feedstock Accounting Module.

$CO_2e_{Emissions,\ n}$ is the total quantity of GHG emissions from operations and allocated embodied emissions for a batch $n$. This can be calculated as:

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

(Equation 7)

Where

• $CO_2e_{Emissions,\ n}$ = the total GHG emissions for a batch $n$, in tonnes of CO₂e
• $CO_2e_{Establishment,\ n}$ = the total GHG emissions associated with project establishment allocated to batch $n$, in tonnes of CO₂e, see Section 8.5.1
• $CO_2e_{Operations,\ n}$ = the total GHG emissions associated with operational processes for a batch $n$, in tonnes of CO₂e, see Section 8.5.2
• $CO_2e_{End-of-Life,\ n}$ = the total GHG emissions that occur after the Reporting Period, $RP$, and are allocated to batch $n$, in tonnes of CO₂e, see Section 8.5.3
• $CO_2e_{Leakage,\ n}$ = the GHG emissions associated with the project’s impact on activities that fall outside of the system boundary of a Project, allocated to batch $n$, in tonnes of CO₂e, see Section 8.5.4

The following sections provide an overview for each variable.

GHG emissions associated with $CO_{2}e_{Establishment,\ n}$ 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.

GHG emissions associated with $CO_{2}e_{Operations,\ n}$ should include all emissions associated with operational activities including but not limited to the SSRs set out in Table 1.

$CO_{2}e_{Operations,\ n}$ emissions must be attributed to the batch $n$ to which they are associated. Allocation may be permitted in certain instances, on a case by case basis, in agreement with Isometric.

$CO_{2}e_{End-of-Life,\ n}$ 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.

$CO_{2}e_{End-of-Life,\ n}$ must be estimated upfront and allocated in the same way as set out for calculation of $CO_{2}e_{Establishment,\ n}$.

Given the uncertain nature of $CO_{2}e_{End-of-Life,\ n}$ emissions, assumptions must be revisited at each Reporting Period and any necessary adjustments made.

$CO_2e_{Leakage,\ n}$ 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 v1.3, projects which would lead to ecological leakage associated with land use change are not eligible under this Protocol.

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:

• Requirements for data quality, including a detailed data quality hierarchy for activity data and emission factors;
• Consideration of materiality in emissions accounting;
• Emissions amortization requirements;
• By-product accounting relating to inputs to the process that are by-products; and
• Waste input accounting relating to inputs to the process that are wastes.

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:

• processing equipment, motors, drives and instrumentation
• facility operations
• pyrolysis system start up
• injection operations
• monitoring equipment operation, including analyzers, instrumentation, on-site laboratories specifically for monitoring activities
• sampling pumps, sampling systems, or other similar monitoring activities
• off site analytical laboratory operation and sample analysis
• electricity for building operation & management for monitoring facility buildings

Examples of fuel consumption may include, but are not limited to:

• pyrolysis system start up
• pyrolysis reactor heating
• emission control (e.g. propane for flare co-firing or pilot)
• handling equipment, such as fork trucks or loaders
• sampling system operation, such as any pumps or heating systems
• monitoring system installation, operation or closure

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:

• non-feedstock conversion process inputs or consumables:
  • catalysts
  • water
  • thermal oils used for heat transfer
  • coolants used for bio-oil quench
  • gasses such as nitrogen used for process or instrumentation purges
  • injection additives (i.e. biocide, salt, etc.)
  • gases, reagents or other materials used for operation of monitoring equipment and on-site analyzers
• equipment:
  • pyrolyzer reactor
  • feedstock conveyors, augers, feed bins, and related equipment
  • bio-oil quench or condenser units, including any heat transfer equipment, such as glycol chillers and pumps
  • ash and char collection systems and quench or cooling systems
  • tailgas emissions control systems, such as flares or oxidizers
  • preparation or mixing equipment
  • pumps, piping, and related equipment
  • storage tanks
  • injection well materials
  • all support structures, facilities, and infrastructure, including steel platforms, framing, supports, concrete footings and building structures
  • monitoring wells and all associated materials (steel casing, concrete, etc.)
  • on-line analyzers, measurement equipment, or other such devices
  • buildings and associated equipment utilized for monitoring purposes (e.g. on-site laboratories)

Transportation emissions are those related to transportation of products and equipment. They may include, but are not limited to:

• transportation of biomass feedstock to processing site
• transportation of bio-oil from processing site to injection site
• transportation of samples for lab analysis

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 $CO_2e_{Emissions,RP}$ in Equation 7 in Section 8.5 should be calculated based on Equation 8 for any shared processes.

$$CO_2e_{Emissions,RP} = (F_{Allocation,RP} \;*\; ( CO_2e_{Establishment,RP} \;+ \;CO_2e_{Operations,RP} \;+ \;CO_2e_{End-Of-Life,RP})) \;+ \;CO_2e_{Leakage,RP}$$

(Equation 8)

Where:

$CO_2e_{Establishment,RP}$, $CO_2e_{Operations,RP}$, $CO_2e_{End-Of-Life,RP}$ and $CO_2e_{Leakage,RP}$ are calculated as per the relevant sections of this Protocol.

$F_{Allocation}$ is the fraction of emissions assigned to the CDR product, represented as:

$$F_{Allocation} = \frac {MJ_{Output, CDR}}{\qquad \sum_{p=1}^n MJ_{Output, p}}$$

(Equation 9)

Where:

$MJ_{Output, CDR}$ is the energy content of the CDR product, equal to the Net Calorific Value, expressed in MJ/kg.

$MJ_{Output}$ 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:

• For electricity outputs, this should be equal to the total quantity of electricity exported over the Reporting Period, converted to MJ;
• For heat this should be equal to the Net Useful Thermal Output exported over the Reporting Period, expressed in MJ; and
• For all other outputs, this should be equal to the Net Calorific Value multiplied by the quantity of product produced and exported over the Reporting Period, expressed in MJ.
• $p$ represents the product

Direct emissions of tailgas as part of a pyrolysis process ($CO_2e_{Tailgas,\ n}$) 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:

$$CO_2e_{Tailgas,\ p}\ =\\ m_{Tailgas} \cdot C_{Tailgas,\ CH_4}\ \cdot GWP_{CH_4}\ \cdot  t_p$$

(Equation 10)

Where:

• $m_{Tailgas}$ = the mass flow rate of tail gas (kg/hr)
• $C_{Tailgas,\ CH_4}$ = the concentration of CH₄ in the tail gas (wt%)
• $GWP_{CH_4}$ = global warming potential of methane, GWP100 using IPCC Sixth Assessment Report (or most recently released IPCC report, whichever is latest)
• $t_p$ = duration of the conversion process operation (hr) for Production Batch $p$

Quantification of $CO_2e_{Tailgas}$ 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 $CO_2e_{Tailgas}$ emissions as the Biomass Accounting Module v1.3 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, $m_{Tailgas}$ can be determined by various acceptable methods, including:

• use of calibrated flow meters to provide continuous volumetric or mass flow measurement. Any flow meter must be calibrated for the composition and density of tail gas⁹, 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 state regulatory authority to perform compliance emissions testing. Testing should be completed for each type of biomass feedstock utilized unless analytical testing (ASTM D5291 ultimate analysis or proximate analysis for moisture, volatiles, fixed carbon and ash) can demonstrate that the feedstocks are similar (within 10% for each component)
• calculation of tailgas amount by a carbon material balance. Material balance calculation will require measurement of biomass weight fed to pyrolyzer and biomass C content, bio-oil product mass and bio-oil carbon content, and ash/char mass with ash/char C content for a given pyrolysis batch using calibrated weigh scales or other calibrated measurement equipment. C content analyses should be performed using ASTM D5291 or equivalent ultimate analysis procedure.

The concentration of CH₄ in the tail gas must be measured directly via one of the following methods:

• on-line analyzer measurement of CH₄ 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 CH₄within +/- 30% of expected average tailgas concentration;
• use of concentration data from 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 state regulatory authority to perform compliance emissions testing. Emissions data should only be used when pyrolysis operating conditions are similar to the conditions under which testing was completed, and for which the biomass feedstock processed during testing is sufficiently similar (within 10% for each component, as outlined earlier).

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:

• Results of any emissions tests used to determine emission rates of CH₄ in tail gas or flow measurements of gas flow from pyrolysis process or associated emission control devices, including signed report from accredited emissions testing entity
• flow rate data from flow meters (including pitot tubes) for each period of interest (batch), 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

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.

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

• Tim Hansen (350 Solutions); Bio-oil Geological Storage Protocol and Energy Use Accounting Module.
• Kevin Fingerman, Ph.D. (Cal Poly Humboldt); Biomass Feedstock Accounting Module.
• Chris Holdsworth, Ph.D. (University of Edinburgh); Bio-oil Storage in Permeable Reservoirs Module.
• Catherine Spurin, Ph.D. (Stanford University); Bio-oil Storage in Permeable Reservoirs Module.
• Wilson Ricks (Princeton University); Energy Use Accounting Module.
• Grant Faber (Carbon-Based Consulting); Transportation Emissions Accounting Module.

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

• Sarah Saltzer, Ph.D. (Stanford University); Bio-oil Storage in Permeable Reservoirs Module.
• Grant Faber (Carbon-Based Consulting); Energy Use Accounting & Embodied Emissions Accounting 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:

• Biomass Feedstock Accounting Module v1.3
• Biomass or Bio-oil Storage in Salt Caverns Module v1.2
• Biomass or Bio-oil Storage in Permeable Reservoirs Module v1.2

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:

Note the Risk Score at any step cannot be negative.

Risk Score Categories:

• 0: Very Low Risk Level (1% buffer)
• 1-2: Low Risk Level (5% buffer)
• 3-4: Medium Risk Level (7% buffer)
• 5+: High Risk Level (10-20% buffer)

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:

• High-potential oxidants
• Temperatures in excess of thermal stability
• Fires
• Microbial degradation

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:

• Seismicity
• Subsurface migration

ASTM D5291-21 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants. (2021, November). https://www.astm.org/standards/d5291

ASTM International. (2018). ASTM D7036: Standard Practice for Competence of Air Emission Testing Bodies. https://www.astm.org/d7036-16.html

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

Carbon Direct & EcoEngineers. (2022). Bio-oil Sequestration Prototype Protocol for Measurement, Reporting, & Verification. https://insights.carbon-direct.com/hubfs/Bio-oil-proto-protocol.pdf

Charm Industrial. (2023). FAQ | Fastest growing carbon removal technology. Charm Industrial. Retrieved June 14, 2023, from https://charmindustrial.com/faq

International Energy Agency. (n.d.). Insights Series 2015 - Storing CO2 through Enhanced Oil Recovery – Analysis. IEA. Retrieved June 14, 2023, from https://www.iea.org/reports/storing-co2-through-enhanced-oil-recovery

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. (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. (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

National Renewable Energy Laboratory. (2016). Quantification of Semi-Volatile Oxygenated Components of Pyrolysis Bio-Oil by Gas Chromatography/Mass Spectrometry (GC/MS) Laboratory Analytical Procedure (LAP). https://www.nrel.gov/docs/fy16osti/65889.pdf

National Renewable Energy Laboratory. (2021, October 7). Determination of Carbon, Hydrogen, Nitrogen, and Oxygen in Bio-Oils Laboratory Analytical Procedure (LAP). https://www.nrel.gov/docs/fy22osti/80967.pdf

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Schmidt, H., Anca-Couce, A., Hagemann, N., Werner, C., Gerten, D., Lucht, W., & Kammann, C. (20118, August 17). Pyrogenic carbon capture and storage. GCB Bioenergy, 11(4), 573-591. https://onlinelibrary.wiley.com/doi/full/10.1111/gcbb.12553

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1. 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. ↩

2. 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. ↩

3. 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. ↩

4. ISO 14064-3: 2019, Section 5.1.7 ↩ ↩²

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

6. https://​​www​​.nrel​​.gov​​/docs​​/fy22osti​​/80967​​.pdf ↩ ↩²

7. https://​​www​​.nrel​​.gov​​/docs​​/fy22osti​​/80967​​.pdf ↩

8. https://​​www​​.nist​​.gov​​/pml​​/owm​​/publications​​/nist​​-handbooks​​/handbook​​-44​​-current​​-edition ↩

9. 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. ↩