Orphaned Well Plugging

Orphaned oil and gas wells are among the largest unowned sources of anthropogenic methane. An orphaned well is one that has no solvent operator to manage it, leaving an open pathway between a hydrocarbon-bearing formation and the atmosphere that no party is obliged to close. As of 2023, states reported more than 141,000 documented orphaned wells across 29 states, a 54% increase on 2020. States also estimate a further 250,000 to 740,000 undocumented orphaned wells whose locations and condition are unknown[^1]. No national inventory attributes emissions specifically to orphaned wells. Because methane is a short-lived climate forcer with a 100-year global warming potential of nearly 30 for fossil-derived emissions, and considerably higher over shorter horizons, abating it exerts disproportionate leverage over near-term warming relative to the same tonnage of CO₂[^2].

Public funding exists but is insufficient relative to the backlog[^3]. Public programs also triage on grounds other than emissions; some states prioritize threats to water resources, public health and safety, and proximity to people, so the highest-emitting wells are not systematically the first to be plugged. Moreover, no state, regardless of funding source, is mandated to identify or measure emissions and few have the personnel or equipment to do so, making emissions as a factor in prioritization currently infeasible. Absent material regulatory reform, carbon finance is among the few mechanisms capable of funding the permanent decommissioning of leaking wells that fall outside the reach of public programs.

Permanent plugging abates these emissions by sealing the wellbore before the methane reaches the atmosphere. This Protocol outlines a process in which a Project Proponent measures the methane emission rate at an eligible orphaned well, permanently decommissions the well by setting plugs across the producing interval, across any sensitive intervals, and at surface in accordance with jurisdictional requirements and recognized industry practice for permanent abandonment, and then re-measures the site to confirm the emission pathway has been closed. The available evidence indicates that properly plugged wells are substantially less likely to leak than unplugged wells and are very unlikely to become high emitters[^4].

This Protocol establishes the requirements and standards for quantifying, reporting, and verifying the greenhouse gas emission reductions achieved when a Project Proponent permanently plugs an orphaned oil or gas well that would otherwise have continued to vent methane to the atmosphere. Because the abated methane is fossil-derived and would have been released in the absence of the Project, the climate benefit is an emission reduction relative to a baseline of continued fugitive emission, not a removal. The Protocol is designed to ensure that any emission reductions claimed are real, additional, independently verifiable, and conservatively quantified. To that end, it describes how Projects must establish that a well is eligible and that its plugging is additional to public plugging programs, measure the pre-plugging emission rate, forecast baseline emissions across the crediting period using a conservative decline function[^5], and account for Project life-cycle emissions from plugging operations and materials.

Specific standards and protocols which are utilized as the foundation of this Protocol, and which this Protocol is intended to be fully compliant with, are as follows:

• 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;
• 42 U.S.C. § 15907 – the federal statutory definition of orphaned well, informing the orphaned well eligibility criteria in this Protocol;
• SPE/PRMS (Society of Petroleum Engineers Petroleum Resources Management System) – the reservoir engineering framework informing decline curve analysis and reservoir supply assessment methodologies in this Protocol;
• 2 CFR 200.307, as informed by the July 2025 U.S. Department of the Interior guidance revision – governing the treatment of carbon credits as programme income for wells receiving IIJA funding, and the associated financial additionality assessment requirements of this Protocol.
• Federal Program Guidelines for Assessing Methane Emissions from Orphaned Wells to meet Reporting Requirements of the 2021 Infrastructure Investment and Jobs Act (BIL)

This Protocol was developed based on the current state of the art and publicly available science regarding orphaned well methane emissions, measurement, and plugging. Because this remains an evolving field, with limited longitudinal data on post-plugging permanence and ongoing research into leak measurement and reservoir characterization methods, the approach taken here may be revised in future versions of the Protocol as the underlying science, field data, and measurement technology advance.

Potential future versions may include, among other developments:

• Expansion of eligibility to undocumented orphaned wells identified through emerging remote-sensing or machine-learning detection methods, as such approaches mature and gain field validation;
• Refinement of the standoff measurement requirements and associated uncertainty discounts set out in Section 8.3.1.2, and of the third-party safety assessment framework in Section 8.3.1.2.1, as additional field-based safety and measurement literature becomes available
• Revision of the capped rise phase treatment in Section 8.3.2.3, including the controlled flow measurement, corrosion models and evidentiary thresholds applied, as improved predictive models for post-intervention wellhead corrosion are developed
• Refinement of the applied decline rates in Section 8.3.2.1, as additional field monitoring data on orphaned well emissions trajectories accumulates beyond what is currently available in the literature;
• Development of additional or improved methods for establishing supplementary reservoir supply evidence under Section 8.3.1.3, including standardized approaches to decline curve analysis for wells with incomplete production histories; and
• Incorporation of additional post-plugging permanence and monitoring data as it becomes available, potentially informing revisions to the reversal risk treatment.

Projects meeting the following applicability criteria are considered eligible for crediting under this Protocol.

To be eligible for crediting, Projects must satisfy each of the following geographic requirements:

• The well must be located within the United States or Canada.
• The well must be an on-shore well.
• Wells located in basins with known high seasonal variability may be subject to additional measurement requirements as determined by Isometric on a case-by-case basis.

To be eligible for crediting, Projects must provide evidence for each of the following well characteristic requirements:

1. Wells must be evidenced as leaking in their ‘as-found’ state
   • Wells must be in compliance with well-spacing requirements to minimize uncertainty due to physical leakage between connected wells impacted by plugging activities[^6].
   • Where well spacing requirements are not met, wells may still qualify by evidencing nearby wells were not completed within +/-15% of its depth
2. Wells must undergo a self-assessment across the following risk categories:
   • Water resource impacts
   • Leaks and spills
   • Threat to public health and safety
   • Threat to environment
   • Proximity to people

For each criteria, projects must demonstrate how their assessment meets local or state regulations. Wells assessed at high risk across four or more of the categories in point 3 are ineligible, due to low confidence around project additionality based on local well-plugging prioritization lists.

To be eligible for crediting, Projects must provide documented evidence of each of the following criteria for every enrolled orphaned well:

• The Project Proponent must demonstrate the well is a documented orphan, with no solvent owner and no continuing beneficial use
• Where the well is an undocumented orphaned well, the Project Proponent must confirm the lack of documentation in the appropriate official local, provincial, or state database, and obtain a regional regulator attestation confirming no solvent operator.
• Projects must demonstrate that neither the Project Proponent nor any company contracted during the plugging process is affiliated with any historically documented operator of the well.
• Projects must demonstrate that measured leaks have been reported to relevant authorities and that confirmation has been received that the well was not scheduled for imminent government plugging.
  • The Project Proponent must obtain correspondence from the relevant authority confirming that the well is not currently scheduled or funded for plugging or leak securing using state or federal funds. For wells appearing on a state funds list, this requirement is met by the evidence required under Section 4.4.
  • The Project Proponent must undertake a regulatory landscape assessment, demonstrating that no reasonably foreseeable state or federal regulatory change over the Crediting Period would materially affect the well's plugging prioritization status. Relevant factors include, but are not limited to:
    • pending or recently received state or federal orphaned well funding allocations;
    • pending legislative or regulatory action to expand plugging funding or accelerate prioritization criteria
• Where a well receives IIJA funds and carbon credits are treated as programme income per 2 CFR 200.307, consistent with the July 2025 DOI guidance revision, the Project Proponent must complete a financial additionality assessment per RMI's recommended framework[^7], comprising a statement of non-prioritization, additional funding ineligibility documentation, or a government attestation.

The following are not eligible for crediting under this Protocol:

• Projects targeting wells that are merely idle and have a solvent, identifiable operator or owner
• Projects targeting wells that do not meet well-spacing requirements, either with documented or undocumented wells, or completion interval overlap requirements
• Projects targeting wells that are located next to coal mines and are legally required to perform safety venting
• Projects targeting wells that have already had plugging activities performed on them and that have been enrolled in another crediting program
• Projects targeting wells that have an active RFP issued on them

By default, this protocol treats projects targeting wells appearing on state funds lists as ineligible. In order for these wells to qualify as eligible, projects must provide correspondence from the relevant authority confirming the emission rate as well as: (a) well-specific evidence that the target well has remained on the list for 3 or more years without plugging action; or (b) a programmatic analysis of the relevant state funds list demonstrating that similarly sized emitting wells listed on it are, on average, not plugged within 3 years of being added.

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 Documentation 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 orphaned well plugging, such as:

• a description of each enrolled well, including its location, well characteristics, and the basis for its classification as an orphaned well under Section 4;
• documentation establishing the Project Proponent’s ownership of each well and/or its environmental attributes;
• documentation of the Project Proponent’s right to plug each well, including transfer of operating rights from the relevant state or provincial authority
• confirmation of landowner permission for every instance in which access to the well site is/was required
• the measurement pathway selected for each well under Section 8.3.1 (non-invasive measurement at the leak point under Section 8.3.1.1, or standoff measurement under Section 8.3.1.2), including, where standoff measurement is used, the third-party safety assessment and outcome category required under Section 8.3.1.2.1, the standoff method used, and the uncertainty discount applied
• the baseline emissions trajectory elected for each well under Section 8.3.2, including any supplementary reservoir supply evidence relied upon under Section 8.3.1.3 and, where the capped rise phase is elected, the controlled flow measurement, choke size, corrosion model and model inputs under Section 8.3.2.3
• the credit release schedule elected for the Project under Section 8.1 (phased time-integrated release or annual ex-post release);
• a description of the quantification methods for gross and net CO₂e reduction; and
• a description of all measurements and methods used to establish the baseline emission rate, cross-referenced with the relevant requirements of Section 8.3.1.

Projects must be validated and net CO₂e reductions verified by an independent third party, consistent with the requirements described in this Protocol as well as in the Validation and Verification Section of the Isometric Standard.

The Validation and Verification Body (VVB) must consider the following requisite components:

• Verify that the T₀ baseline measurement was obtained in accordance with the requirements of Section 8.3.1, including, where standoff measurement was used, that the third-party safety assessment requirements of Section 8.3.1.2.1 were satisfied and the applicable uncertainty discount was applied
• Where the capped rise phase is elected, verify that the controlled flow measurement and corrosion model application satisfy the requirements of Section 8.3.2.3
• Verify that the quantification approach and monitoring plan adhere to the requirements of Section 10, including demonstration of required records;
• Verify that post-plug monitoring and permanence requirements under Section 9 have been met at each applicable checkpoint;
• Verify that the Environmental & Social Safeguards outlined in Section 6 are met; and
• 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 Materiality Section of the Isometric Standard.

Verifiers should also verify the documentation of uncertainty of the GHG Statement, as required by the Uncertainty Accounting Section of the Isometric Standard. Qualitative Materiality issues may also be identified and documented, such as:

• data and document control issues that erode the verifier's confidence in the reported data, including inconsistent or incomplete well ownership and transfer records;
• poorly managed documented information;
• difficulty in locating requested information; and
• noncompliance with regulations indirectly related to GHG emissions, reductions, or well plugging, including state well-plugging permitting requirements.

Project Validation and Verification must incorporate site visits in accordance with the requirements of ISO 14064-3, 6.1.4.2, including, at a minimum, a site visit during the first Validation or Verification of a Project. Site visits should, where feasible, coincide with the T₀ measurement campaign, so that the verifier may directly observe measurement practice.

Verifiers should, whenever possible, observe the T₀ measurement, any controlled flow measurement under Section 8.3.2.3, the plugging operation, and any post-plug monitoring event to ensure full documentation of process inputs and outputs through visual observation and validation of instrumentation, measurements, and required data quality measures.

VVB teams must maintain and demonstrate expertise associated with the specific technical disciplines relevant to this Protocol, including reservoir engineering, oil and gas well safety and mechanical integrity, methane measurement instrumentation and methods (including chamber-based and other non-invasive methods at the leak point, standoff methods, and controlled flow measurement), and well plugging and abandonment practice.

All VVBs are approved by Isometric independently and impartially based on alignment with Conflict of Interest policies, rotation of VVB policies, oversight on quality and the following requirements:

• VVBs must be able to demonstrate accreditation from:
  • an International Accreditation Forum member against ISO 14065 or other relevant ISO standard, including but not limited to ISO 14034, ISO 17020, ISO 17029; or
  • a relevant governmental or intergovernmental regulatory body.
• Alternatively, VVBs may be approved on a case-by-case basis if they are able to demonstrate to Isometric that they satisfy all required Verification needs and competencies required for this Protocol and follow the guidelines of ISO 19011 or other relevant standards.

An orphaned well typically reverts to the surface estate upon becoming orphaned, such that the equipment and wellbore are owned by the landowner rather than any prior operator. Accessing and testing the well, including obtaining the T₀ measurement under Section 8.3.1, requires the landowner's permission but does not itself confer ownership and liability of the well or its associated Credits. Where a Project proceeds to plugging, the Project Proponent must obtain an assignment of the well from the surface owner with continuing access that allows for post-plug monitoring in accordance with requirements set forth in this methodology, marketable title of the carbon credits generated under this methodology, and the operating rights required to plug the well from the relevant state or provincial authority (for example, a Form 1073 if operating in Oklahoma or equivalent transfer, where applicable).

Where multiple parties are involved in a Project, for example, if the party conducting the T₀ measurement, the party plugging the well, and the party holding the operating rights are distinct entities, the Project Proponent must be specified contractually as the sole owner of the Credits to avoid double counting of net CO₂e reductions. The Project Proponent must retain documentation of the chain of ownership and rights transfer from the surface owner through to plugging as part of the PDD.

The Project Proponent must demonstrate additionality through compliance with the Additionality Section of the Isometric Standard. The baseline scenario and counterfactual used to assess additionality must be project-specific, as described in Section 7.2 of this Protocol.

Where a well has received, or is eligible to receive, federal or state funding for plugging (for example, funds allocated under the Infrastructure Investment and Jobs Act (IIJA)), the financial additionality assessment must account for the interaction between that funding and the Project's reliance on Carbon Finance. The Project is ineligible where the financial additionality assessment shows that the well would have been plugged absent Carbon Finance, including where other available revenue sources, such as public funding, would have been sufficient to enable plugging without the Project.

Additionality must also be assessed from a regulatory standpoint (see Section 4.3). The Project Proponent must demonstrate that the relevant state or federal government would not, absent the Project, have undertaken plugging of the well within the Crediting Period. Additionality determinations must be reviewed and completed every Crediting Period.

The uncertainty in the overall estimate of net CO₂e impact as a result of the Project must be accounted for. The total net CO₂e impact for a specific Reporting Period must be conservatively determined, and Projects must conduct an uncertainty analysis for the net CO₂e impact calculation in compliance with requirements outlined in Section 2.5.7 of the Isometric Standard.

Projects must report a list of all input variables used in the net CO₂e reduction calculation and their uncertainties, including:

• the T₀ baseline emission rate, E₀, and its measurement uncertainty, including, where standoff measurement was used, the uncertainty discount applied under Section 8.3.1.2;
• the decline rate applied under Section 8.3.2.1 and the basis for its selection (default emitter-class rate or adjusted rate) and, where the capped rise phase is elected, the controlled flow rate $E_{CF}$, choke size, corrosion model inputs and resulting rise rate $r_{CM}$ under Section 8.3.2.3;
• the reservoir supply evidence relied upon under Section 8.3.1.3, where applicable;
• emission factors utilized, as published in public and other databases used; and
• a summary of the data handling, processing, and error propagation approach.

The uncertainty information should at least include the minimum and maximum values of each variable. More detailed uncertainty information should be provided if available, as outlined in the Uncertainty Accounting 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 so that the results can be re-created. Parameters may be omitted from a full uncertainty analysis if a sensitivity analysis can demonstrate that the parameter contributes to less than a 1% change in the net CO₂e reduction. For all other parameters, information about uncertainty must be specified.

Uncertainty deductions are applied throughout this Protocol to account for measurement and model uncertainty in the emission reduction calculation. Rather than being applied as a single blanket discount, uncertainty is addressed at the specific points in the methodology where it arises:

• Corrosion model uncertainty. The cap on the rise phase at 1.25× E₀ (Section 8.3.2.3), equivalent to a maximum linear rise of 2.5% of E₀ per year over 10 years, constrains the maximum permissible increase in leak rate attributable to corrosion, limiting the effect of uncertainty in corrosion model outputs (e.g., de Waard–Milliams) on the credited trajectory.
• Decline rate uncertainty. The use of a P80 adjustment to terminal decline rates (Section 8.3.2.1) accounts for uncertainty in reservoir decline behaviour and leak rate variability over time, applying a conservative decline rate rather than the unadjusted best estimate.
• Standoff measurement uncertainty. Where E₀ is established by standoff measurement under Section 8.3.1.2, a method-specific uncertainty discount is applied before the measurement is used as E₀, determined on a case-by-case basis with reference to the documented accuracy of the method used.

Each uncertainty deduction targets a distinct source of uncertainty and applies only where its corresponding condition is met. The standoff discount applies only where E₀ is established by standoff measurement, the rise-phase cap only where the capped rise phase is elected, and the P80 decline rate unless the Project qualifies for the adjusted decline rate under Section 8.3.2.1.

In accordance with the Data Sharing Section of the Isometric Standard, all evidence and data related to the underlying quantification of the net CO₂e reduction will be available to the public through Isometric's platform. This includes:

• the Project Design Document;
• the GHG Statement;
• measurements taken, including the T₀ measurement record, any controlled flow measurement and corrosion model inputs under Section 8.3.2.3, and any post-plug monitoring data;
• emission factors and decline rates used; and
• scientific literature used.

The Project Proponent can request certain information to be restricted, available only to authorized Buyers, the Registry, and the VVB, where it is subject to confidentiality. However, all other numerical data produced or used as part of the quantification of net CO₂e reduction will be made available.

In line with Section 5.7 of the Isometric Standard, the emission reduction credited under this Protocol may be claimed only once. Where the reduction is sold as Credits under this Protocol, the same reduction must not additionally be claimed by the Project Proponent, the surface owner, any state or federal funding programme, or any other party as a reduction in a voluntary or regulatory greenhouse gas inventory, or as a book-and-claim or mass-balance attribute allocated to a third party.

This does not prevent any party from meeting a mandatory regulatory reporting obligation on the basis of its actual measured emissions. Nor does it prevent a well from receiving state or federal plugging funds concurrently with Project crediting, where the financial additionality assessment under Section 5.4 has been satisfied and the funds are treated as programme income rather than a parallel emission reduction claim.

Before the issuance of Credits, and at each verification event and annually thereafter, the Project Proponent must provide a signed affidavit confirming that the credited reduction has not been and will not be claimed by any party other than through the retirement of Credits issued under this Protocol. The Project Proponent must disclose any state or federal funding received or applied for in connection with the well, and any other voluntary or compliance claim programme associated with the well, so the VVB can confirm no parallel claim is being made.

Credits issued under this Protocol depend on Project Proponents implementing, transparently reporting, and independently verifying a comprehensive set of environmental and social safeguards, in line with the Isometric Standard. Isometric's approach to Environmental and Social Safeguarding (ESS) is holistic: the risks a Project introduces must be weighed against the climate benefit it delivers, so that responsible innovation is supported rather than assumed.

An orphaned well Project proceeds through several distinct stages: locating and characterizing the well, taking an on-site baseline measurement (Section 8.3.1), securing and plugging the well, and monitoring it afterward. Each of these stages carries its own hazard profile. Well sites can present pressurized gas, hydrogen sulfide, and other legacy contamination, and the land itself is typically owned by a party with no operational role in the Project. Consistent with the Environmental and Social Impacts Section of the Isometric Standard, responsibility for demonstrating that a Project causes no net environmental or social harm sits with the Project Proponent throughout, whether a given stage is carried out directly or through a landowner, safety consultant, or plugging contractor.

Safeguards under this Protocol must align with the Integrity Council for the Voluntary Carbon Market's (ICVCM) Core Carbon Principles, as follows:

• Compliance. Every stage of a Project must comply with applicable federal, state, provincial, and local law, including well-plugging permits, occupational safety and health requirements (including OSHA's general duty clause, where relevant), and the requirements governing transfer of well ownership and operating rights described in Section 5.3. The PDD must list every permit, approval, and rights transfer applicable to the wellbore, along with its current status and compliance history.
• Risk Identification. Consistent with the Isometric Standard, Project Proponents must identify and assess the environmental and social risks arising at each stage of a Project. At minimum, this assessment must cover:
  • the risk of blowout or uncontrolled release inherent in measuring and plugging a well of unverified mechanical integrity, along with occupational exposure to hydrogen sulfide and other hazardous gases and hazards posed by degraded surface equipment;
  • risks to public health and safety where a well sits near occupied structures or public infrastructure, whether arising from the plugging activity itself or the well's pre-existing condition;
  • risks of surface or groundwater contamination where a well is located near sensitive water resources;
  • impacts on the surface owner's interests, including site access, disruption during measurement and plugging, and restoration afterward;
  • impacts arising from the management and disposal of produced water, brine, or other fluids and materials encountered during plugging, separate from the methane emission addressed elsewhere in this Protocol;
  • the condition of the well pad and surrounding site following plugging, including whether it is restored to a condition consistent with surrounding land use; and
  • the risk of encountering contamination unrelated to the well's methane emissions during site access, measurement, or plugging (Section 6.4.3).
• Impact Assessment and Mitigation. For each risk identified, the Project Proponent must assess its potential impact and set out a mitigation strategy, weighing the harm against the Project's climate benefit and any co-benefits, including the removal of a standing safety and environmental hazard from the landowner's property. These assessments may be qualitative or quantitative.
• Monitoring and Adaptive Management. Mitigation measures must be paired with a monitoring plan sufficient to confirm they are working. Project Proponents must also have a remediation plan ready in advance, covering how they would respond to harm resulting from the Project, including an uncontrolled release or blowout during measurement or plugging, and must carry out any remediation required as a result of the Project, in line with the Isometric Standard.

Measuring and plugging an orphaned well means approaching and manipulating equipment whose mechanical condition is, by definition, unverified. A well may exhibit elevated pressure, hydrogen sulfide, or visible signs of equipment failure well before it is ever touched. Handled poorly, these conditions can lead to blowout, uncontrolled release, or harm to personnel, the landowner, or the surrounding environment. This Protocol addresses that risk primarily through the third-party safety assessment set out in Section 8.3.1.2.1, which determines whether a well may be approached for non-invasive measurement at the leak point or must instead be measured by standoff methods, and which, for wells assessed under Category 3, requires that work proceed under a well-specific well control and equipment plan. Beyond the per-well assessment, Project Proponents must provide evidence showing they are operating to a standard consistent with broader industry practice for well intervention, including documented safety programmes, appropriately certified personnel, and a site-specific emergency response plan for each well.

Many orphaned wells sit in locations without existing road access adequate to support the equipment needed for measurement and plugging, particularly in remote or historically undeveloped areas. Where a Project requires the construction of a new access road, the improvement of an existing one, or the clearing of land to stage equipment, this activity is a project impact in its own right and must be addressed separately from the well-intervention risks covered in Section 6.2.

Project Proponents must identify any new or upgraded infrastructure required to support a Project and assess its environmental and social impact, including:

• disturbance to soil, vegetation, and habitat along the access route and at any staging area;
• impacts on surface water drainage or nearby water resources arising from construction activity;
• effects on the surface owner's use of the land beyond the well site itself, including any land outside the immediate well pad required for access or staging; and
• whether the infrastructure will be removed and the land restored following plugging, or left in place, and the basis for that decision.

Where new infrastructure is required, the Project Proponent must set out a plan for minimizing its footprint and, where the infrastructure is not intended for continued use following plugging, a plan for restoration. Landowner consent must extend to the specific infrastructure required, not only to well access itself, and the terms of that consent must be documented as part of the ownership and rights records required under Section 5.3.

Plugging an orphaned well involves more than sealing the source of methane emissions. It typically requires handling fluids and materials at the wellhead, leaves surface equipment and disturbed ground that must be dealt with once the work is complete, and may bring the Project Proponent into contact with contamination that predates the Project and has nothing to do with the well's leak. Each of these is addressed below.

Where plugging activity involves the handling of produced water, brine, drilling fluids, or other liquid or solid waste at the well site, the Project Proponent must identify the applicable disposal or treatment requirements and confirm that these materials are managed in accordance with them. This includes documenting the volume and type of material handled, the disposal method used, and the party responsible for disposal where this is not the Project Proponent directly.

Following plugging, the Project Proponent must restore the well pad and any disturbed area at the site to a condition consistent with the surrounding land use, unless the surface owner agrees otherwise in writing. Restoration must address, at minimum, the regrading of disturbed ground, and revegetation where the site was previously vegetated. The Project Proponent must document the condition of the site prior to plugging and confirm the condition of the site following restoration, and this documentation forms part of the required records under Section 10.

Where a Project Proponent encounters evidence of contamination at a well site that is unrelated to the well's methane emissions, for example legacy soil or groundwater contamination from prior operations, the Project Proponent must document the discovery and report it to the relevant state, provincial, or local regulatory authority in accordance with applicable law. Such contamination is not addressed or remediated under this Protocol, and its discovery does not affect a Project's eligibility for crediting, provided the Project Proponent has met its disclosure and reporting obligations. Isometric may request documentation of any such discovery and its disclosure as part of validation or verification.

The scope of this Protocol includes GHG sources, sinks and reservoirs (SSRs) associated with an orphaned oil and gas well plugging 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 reductions associated with The Project may be direct emissions from a process, or indirect emissions from combustion of fuels, electricity generation, or other sources. Emissions must include all GHG SSRs within the system boundary, from the identification and characterisation of the well, through the measurement campaign, the plugging and abandonment operation and the reclamation of the wellsite, to the post-plug permanence checks and the disposal of recovered equipment and materials. 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 Project must be fully considered in the system boundary. Any activity that ultimately leads to the issuance of Credits must be included in the system boundary.

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 1. If any GHG SSRs within Table 1 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 the system boundary for an orphaned well plugging Project. [FIGURE UNDER PRODUCTION]

Table 1. Project System Boundary

Miscellaneous GHG emissions are those that cannot be categorised 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.

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 (N₂O) and fluorinated gases such as hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF₆) and nitrogen trifluoride (NF₃). For the fugitive methane comprising the baseline, only CH₄ shall be included in 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 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 (see Section 8.4.4.2).

The baseline scenario represents the business-as-usual condition, describing the fugitive methane emissions that would have occurred in the absence of the Project. Under this Protocol, the baseline is the condition in which the well remains unplugged and unremediated for the duration of the Crediting Period, with fossil methane continuing to migrate from the reservoir to the atmosphere through the wellbore, the wellhead and the well annulus.

The eligibility requirements for baseline conditions, including evidence that no solvent operator exists, that the well has no beneficial use, and that the well is not scheduled for plugging under a government programme, are defined in Section 4.3.

The baseline quantification accounts for CH₄ emissions from the wellbore and from legacy surface equipment directly connected to the wellbore, where those emissions are confirmed to cease upon plugging. Residual hydrocarbons held in onsite storage tanks are excluded, as they are a finite source not sustained by reservoir supply and their release is not prevented by plugging. Fossil CO₂ and other GHGs present in the escaping gas stream are also excluded from the baseline; although plugging prevents their release, omitting them understates the reduction and is therefore conservative. All other GHG sources are accounted for entirely as project-side emissions, where only the additional or incremental emissions attributable to the project activity are quantified (see Section 8.4).

The baseline scenario is not observable once the well is plugged. Its quantification is therefore established from the measurements taken before intervention and projected forward across the Crediting Period, as set out in Section 8.3.

Leakage comprises increases in GHG emissions occurring outside the system boundary defined in Section 7.1 as a result of the Project activity. Consistent with the Isometric Standard, the Project Proponent must assess leakage arising from activity shifting, market transformation, and shifts in ecosystem processes.

Market and activity-shifting leakage is not considered material under this Protocol, and the Project Proponent is not required to quantify it. Isometric will revisit this position if evidence emerges that orphaned well plugging Projects cause systematic changes.

Orphaned well projects may, however, encounter a risk of environmental leakage. This relates to the risk that plugging an enrolled well alters pressure conditions in a shared reservoir such that emissions increase at another well. Published guidance identifies compliance with local well-spacing requirements as one of several acceptable measures for managing this risk[^7], while noting that it is not established whether modern well-spacing requirements are sufficient to prevent inter-well communication following plugging.

To mitigate against this, this Protocol does not consider wells eligible that do not satisfy local well spacing requirements or completion interval requirements. Because compliance is assessed against wells recorded in the applicable well database, and a proportion of orphaned wells are undocumented, Project proponents must also complete a visual inspection of the surrounding area to identify any undocumented well that would violate these requirements. Where such a well is identified, the Project is ineligible under Section 4.4.

The visual inspection must cover the area within the applicable spacing distance of the Project well and must be completed before plugging. The Project Proponent must document the radius assessed and its basis in the applicable spacing requirement, the method used and the extent of the area observed, any vegetation, terrain, structures or access restrictions limiting visibility over any part of that area, and any well or surface indication of a well identified.

Unlike a continuously monitored emissions source, an orphaned well's baseline methane emissions are established through a discrete measurement campaign just before the point of intervention (T₀) and subsequently projected forward for the Crediting Period under a decline or rise trajectory (see Section 8.3.2). The calculation of net emission reductions must therefore reconcile a limited number of point-in-time baseline measurements with an extended, multi-year crediting horizon over which no further direct measurement of the counterfactual leak occurs.

To structure this, calculations are performed over an interval of time defined as the Reporting Period, RP, over which the applicable segment of the baseline trajectory, project emissions, and any post-plug monitoring obligations due within that interval are assembled into a single net CO₂e reduction. The Reporting Period is the common interval across which the Project Proponent compiles data for verification and issuance. A Reporting Period is 12 months in length, measured from T₀, such that Reporting Period n covers the interval $t \in [n-1, n]$ on the baseline trajectory. For this protocol, the Crediting Period is set at 20 years.

Net CO₂e reduction is calculated for each Reporting Period, written hereafter as $CO_2e_{Reduction,\ RP}$. The final quantification must be conservatively determined, consistent with the baseline decay/rise treatment set out in Section 8.3.2 and the applicable emitter class decline rate (8.3.2.1).

The Project Proponent must select one of two credit release schedules for a Project, selected at the time of the Project Design Document and applied consistently for the duration of the Crediting Period:

1. Phased time-integrated release: an upfront, 20-year time-integrated credit based on the conservative baseline decline curve, released in two tranches. The first 80% following successful project validation and verification, and the remaining 20% following the subsequent verification at month 12–18 following the post-plug permanence check described in Section 9.1.
2. Annual ex-post release: credits issued annually, following each successive verification event, in proportion to the corresponding segment of the baseline decline curve for that Reporting Period.

Both schedules draw on the same underlying baseline trajectory and are subject to the same post-plug monitoring and permanence requirements set out in Section 9; the choice between them affects only the timing of credit issuance and imposes no additional verification, measurement, or documentation burden on the Project Proponent or the VVB beyond what is already required under this Protocol. The schedule selected does not alter the underlying quantification approach set out in the remainder of this Section, only the Reporting Period(s) against which the resulting Credits are issued.

In line with the Isometric Standard, Credits are issued only once the well has been plugged and the applicable validation or verification event under the selected schedule has occurred. Credits may only be issued for the portion of the projected baseline trajectory attributable to the Reporting Period in which the corresponding event occurred.

Net CO₂e reduction for a Reporting Period is calculated as:

$$CO_2e_{Reduction,\ RP} = CO_2e_{Baseline,\ RP} - CO_2e_{Project,\ RP}$$

(Equation 1)

Where:

• $CO_2e_{Reduction,\ RP}$ is the total net CO₂e reduction for the Reporting Period, RP, in tonnes CO₂e.
• $CO_2e_{Baseline,\ RP}$ is the quantity of fossil methane, expressed as CO₂e, that the well would have emitted to the atmosphere over the Reporting Period in the absence of the Project.
• $CO_2e_{Project,\ RP}$ is the total GHG emissions, expressed as CO₂e, arising from the Project over the Reporting Period.

The baseline is determined as follows:

$$CO_2e_{Baseline,\ RP} = CO_2e_{Trajectory,\ RP} - CO_2e_{Counterfactual,\ RP}$$

(Equation 2)

Where:

• $CO_2e_{Trajectory,\ RP}$ is the quantity of methane, expressed as CO₂e, that the applicable baseline emissions trajectory projects the well would have emitted over the Reporting Period, calculated as set out in Section 8.3.2.
• $CO_2e_{Counterfactual,\ RP}$ is the portion of that projected emission that would have been avoided regardless of the Project, in tonnes of CO₂e — for example, where the well would have been plugged under an existing state or federal programme absent Project intervention. This term is zero for a Project meeting the eligibility requirements of Section 4.3 and 4.4, as set out in Section 8.3.3.

Both terms in Equation 2 describe the well's emissions in the absence of the Project. Both are derived from a single measured quantity established once, at the point of intervention, defined as T₀.

• T₀ is the origin of the time axis for the baseline trajectory, such that $t = 0$ at T₀.
• E₀ is the well’s as-found methane emission rate, expressed as a volumetric flow of methane at standard conditions (60 °F and 14.696 psia), in MCF/d, determined in accordance with Section 8.3.1. Where a measurement method reports total gas flow, the result must be multiplied by the methane mole fraction measured at T₀.

$E_0$ is the sole measured input setting the level of the baseline. The controlled flow rate $E_{CF}$ under Section 8.3.2.3 additionally informs a project's rise phase, but does not set the baseline level. $E_{BL}$ is obtained by projecting E₀ forward

Because the well's unmitigated emission rate is not measured again after plugging, the conservatism of the reduction claim rests on the conservatism of the rate established at T₀ and of the trajectory and decline rate applied to it, over the full duration of the Crediting Period, rather than on a continuously measured emissions quantity.

Quantification of the leak rate must use on-site measurement of the well's passive methane emission rate at the point of intervention (T₀). Two passive measurement pathways are available: non-invasive methods at the leak point (typically chamber-based measurements), which is the default, and standoff measurements taken in the vicinity of the leak, which are permitted only where the third-party safety assessment under Section 8.3.1.2.1 returns a Category 3 outcome. The measurement obtained under either pathway, $E_0$, is the starting value used in the trajectory calculations of Section 8.3.2. In both pathways, Projects must attest in the PDD that they did not manipulate or modify the as-found leak (e.g., operating valves, tightening or replacing fittings, venting, shutting in, sealing or enhancing leak points) between site discovery and completion of the E₀ measurement.

Non-invasive measurements determine the well's as-found methane concentration and flow rate at an unaltered, leaking well directly at the leak point. This option is grounded entirely in the measurement of an active leak and requires no modeled assumptions about the well's condition. Acceptable methods include:

• Dynamic chamber-based methods
• High-flow sampling
• Bag sampling

Other types of non-invasive methods may be permitted in agreement with Isometric[^8]. Measurements must be made by a qualified measurement specialist who meets the guidelines outlined in the Federal Program Guidelines for Assessing Methane Emissions from Orphaned Wells to meet Reporting Requirements of the 2021 Infrastructure Investment and Jobs Act (BIL)[^9], including all the requirements for trainings and experience with the specific equipment type.

Measurements must not be taken under high wind or extreme temperature conditions. The weather/environmental conditions under which the measurement method is effective should be documented.

Projects must undertake twelve measurements, at an interval of one measurement at least every 15 minutes, over a 3-hour sampling period. Instrumentation must meet manufacturer-stated accuracy specifications appropriate to the measurement method employed (e.g., ±2% of reading for thermal mass flow meters, ±5% of reading for portable methane analyzers/TDLAS units). Stability across the 12 measurements is assessed via the coefficient of variation (CV), which must be reported in a Project's GHG Statement at each verification.

$$E_{0,testn} = (1/12) \sum_{i=1}^{12} m_i$$

(Equation 3)

Where $m_i$ is the measured methane mass flow rate at measurement $i$.

A second, independent 3-hour sampling event, following the same requirements as Section 8.3.1.1.2, is required between 2 and 26 weeks of the initial test. The mean rate of this second event must stabilize within 10% of the first to establish a representative baseline. Where both events stabilize within tolerance, the Project Proponent must specify in the PDD which value, or combination, is used as $E_0$.

$$E_0 = min(E_{0,test1}, E_{0,test2})$$

(Equation 4)

Wells for which the mean of the first test event is 30 MCF/d or greater are subject to an additional stability test, conducted 30–60 days following the second test. Additionally, wells that are not stable (>10% difference) after two rounds of measurement are also subject to an additional stability test.

• Where the third test's average rate falls within ±10% of the average of the first two tests, the well is confirmed on a stable three-test baseline.
• Where the third test does not stabilize within ±10%, the Project Proponent may either continue testing until the stabilization threshold is reached, or use the lowest of the three test averages as $E_0$.

$$E_0 = min(E_{0,test1}, E_{0,test2}, E_{0,test3})$$

(Equation 5)

Standoff measurements are deployed where the well cannot be approached for a non-invasive measurement due to justified and evidenced safety concerns. They are only permitted where an independent third-party safety assessment under Section 8.3.1.2.1 concludes that engineered intervention is required (Category 3, Section 8.3.1.2.1.3). Without that determination, the well must be measured under the default non-invasive passive measurement at the leak site in Section 8.3.1.1.

Standoff measurements may include aerial technologies or ground technologies placed at a sufficient setback distance. Acceptable methods include, but are not limited to, RMLD combined with a dispersion model, Gaussian plume modeling, aerial drone surveys[^10]. Because standoff methods carry a different, and generally less favorable, accuracy profile than non-invasive measurements taken at the leak point, an uncertainty discount will be applied to this measurement before it is used as $E_0$. The size of the discount will be decided on a case by case basis according to the specific standoff method used and the literature available (e.g. for an empirically-derived dispersion parameter version of Gaussian plume, a ~25% uncertainty discount, accounting for the 15% bias[^11] and adjusted to reflect realistic variability in field execution).

Project must also agree their sampling resolution with Isometric, based on the standoff method selected. Alternative methods and technologies not explicitly named above will be reviewed by Isometric on a case-by-case basis.

A Project Proponent seeking to depart from the default non-invasive measurement at the leak point under Section 8.3.1.1 on safety grounds must obtain a written assessment from an independent, qualified assessor meeting the requirements of Sections 8.3.1.2.1.4 and 8.3.1.2.1.5.

The assessment is an engineering determination of which activities the available evidence supports at the well. The assessor is not required to calculate an exact failure probability. However, the assessment must state explicitly which activities the evidence supports and which remain unresolved, and it must conclude with one of the outcome categories in Section 8.3.1.2.1.3.

Scope of Assessment. At a minimum, the assessor must:

• review available well records;
• inspect the well from a position appropriate to the observed conditions;
• document observable defects and releases;
• identify nearby receptors, including those identified under Section 6.1;
• examine the proposed measurement arrangement; and
• determine whether routine approach to, or manipulation of, the well should be restricted.

Assessment Indicators. The assessment must consider each of the following indicators. For each, it must record whether the indicator was observed, not observed, or could not be safely assessed.

• Unexplained changes in pressure or flow over time, where safely obtainable.
  • Rising pressure, repeated pressure or flow excursions, or increasing discharge under unchanged conditions warrant reassessment. Instrument effects and changing ambient conditions must be distinguished from genuine changes in well behavior.
• Mechanical distress at the pressure boundary.
  • Cracking, deformation, connection movement, failed fasteners, or leakage through a component body can indicate compromised containment. Their significance depends on location, loads, and service history.
• Intermittent or increasing liquid, gas, or solids discharge.
  • Slugging, forceful liquid ejection, or sand or debris discharge can indicate changing flow conditions and introduce impact, erosion, and exposure hazards.
• New or expanding release pathways.
  • New annular flow, discharge around the well base, or gas or fluid emerging through soil can indicate that the assumed flow path is incomplete or changing.
• Changing sound or vibration.
  • An increasing roar, pulsation, rattling, or component vibration says more about a change in well condition than the mere presence of a steady hiss.
• Developing frost or other thermal changes.
  • These warrant assessment of expansion cooling, liquids, freezing, and possible restriction. Frost alone does not quantify pressure or remaining equipment strength.
• Gas detection or an observed plume.
  • These are useful for locating a release and assessing atmospheric hazard. They are not, on their own, sufficient to determine upstream pressure or blowout potential.

Assessment Outcomes. The assessment must conclude with one of the following categories:

• Category 1: Limited non-invasive measurement permitted. The identified method may proceed under the site, atmospheric, equipment, and stop-work conditions stated in the assessment. The well must be measured by non-invasive measurement at the leak point under Section 8.3.1.1.
• Category 2: Additional information or specialist review required. No imminent failure is asserted, but the available evidence is insufficient to support the proposed task. The proposed measurement may not proceed until a second assessor, meeting the same requirements, completes a follow-up review that recategorizes the well under Category 1, 3, or 4.
• Category 3: Engineered intervention required. Work must proceed under a well-specific well control and equipment plan, not a routine measurement procedure. Non-invasive measurement at the leak point under Section 8.3.1.1 is ruled out. E₀ must be established by standoff measurement under Section 8.3.1.2. Where the capped rise phase is elected, the controlled flow measurement under Section 8.3.2.3 must be conducted under the well control and equipment plan.
• Category 4: Routine work prohibited; emergency assessment or response required. The observed conditions, or their credible consequences, require withdrawal, exclusion, notification of the relevant state regulator, or a specialist emergency response. The well is temporarily ineligible under this Protocol. It may be re-enrolled only if a subsequent assessment under this Section recategorizes it under Category 1, 2, or 3.

Assessor Qualifications. The assessor must hold at least one of the following qualifications:

• Lead well integrity/intervention assessor. Demonstrated experience with well servicing, pressure control equipment, barrier assessment, and plugging and abandonment of comparable legacy wells. Appropriate engineering licensure must be confirmed where the work requires it.
• Well control operational specialist. Current, role-appropriate IADC WellSharp Well Servicing training or an appropriately scoped IWCF Well Intervention Pressure Control qualification, together with actual field experience.
• Equipment condition/NDT specialist. A method-specific nondestructive testing qualification, suitable procedures, and relevant experience with the specific component and damage mechanism being examined.

None of the following, on its own, is sufficient to qualify an assessor:

• a general professional title;
• H₂S awareness training;
• an OSHA 10- or 30-hour course;
• carbon verification accreditation; or
• an unspecified claim of being "API certified."

A geologist may provide important evidence on the formation and pressure source. However, determinations of mechanical integrity and intervention require the distinct competence set out above. The assessor's qualifications must be documented in the PDD with supporting evidence, such as licensure, training certificates, and a record of relevant field experience.

The assessor, and any second assessor under Category 2, must be independent. They must not be affiliated with the Project Proponent, any current or former operator of the well, or any contractor engaged in plugging the well.

The following must be retained and made available to the VVB:

• the signed assessment, including the outcome category;
• the record of each indicator under Section 8.3.1.2.1.2;
• dated and geo-tagged photo or video evidence of observed conditions;
• where applicable, the second assessor's review; and
• for Category 3, the well control and equipment plan.

In addition to the T₀ emission rate (E₀) established under Sections 8.3.1.1 or 8.3.1.2, the Project Proponent must provide supplementary evidence that the reservoir connected to the well can sustain the measured leak rate over the full Crediting Period.

This requirement has two functions. First, it is a ceiling check against which the plausibility of E₀ is assessed. Second, where it is satisfied to a higher standard, it may support use of the adjusted, lower decline rate under Section 8.3.2.1. Reservoir supply evidence does not set E₀ or the decline rate, but may limit the total quantity credited under Section 8.3.1.3.2.

For the purposes of this Section, remaining connected gas means the volume of gas meeting all of the following conditions:

• it is held in the zone(s) supplying the leak path;
• it is capable of flowing to the well before reservoir pressure declines to the abandonment pressure, defined as the reservoir pressure at which flow from the zone to the leak path would cease, as determined and documented by the Reservoir Engineer;
• it is net of all gas produced from, and all gas estimated to have leaked from, the well before T₀.

The Project Proponent must estimate remaining connected gas using one of two options:

• Option 1: decline curve analysis of historical production data; or
• Option 2: a shut-in pressure-based estimate, using either volumetric estimation or material balance.

Every estimate must be conducted, or reviewed and approved, by a Reservoir Engineer meeting the requirements of Section 8.3.1.3.3. Where the Project Proponent performs more than one option or method, it must report the result of each and must use the lowest resulting estimate for the purposes of Section 8.3.1.3.2 and Section 8.3.2.1.

For both options, the Project Proponent must also meet the following requirements:

• The Project Proponent must identify the zone(s) supplying the leak path, referencing publicly available completion records (e.g. state-level completion forms identifying producing zone(s)) where they exist.
• The Project Proponent must estimate the gas leaked between the date the well became orphaned and T₀ by back-projecting E₀ over that interval at the default annual decline rate for the well's emitter class under Section 8.3.2.1. The result must be deducted from the estimate under either option.

1. Decline curve analysis using historical production data. The Project Proponent must estimate remaining reservoir volume using decline curve analysis applied to the well's historical production record, performed in accordance with generally accepted reservoir engineering practice and conducted or reviewed by a qualified reservoir engineer. The production history window used must exclude, at minimum, the final 24 months of recorded production prior to the well becoming orphaned, as this period is not considered representative of sustained well performance. The Project Proponent must document the decline model applied (e.g. exponential, hyperbolic, or harmonic), the parameters used, and the basis for their selection, together with the resulting remaining volume estimate, in the PDD. Where publicly available completion records (e.g. state-level completion forms identifying producing zone(s)) exist, they must be referenced to confirm the producing zone(s) associated with the production history used.

2. Shut-in Pressure-Based Estimate

   The Project Proponent may estimate remaining connected gas from a current shut-in pressure measurement, using either volumetric estimation (Method 2a) or material balance (Method 2b). If both methods are performed, the lower estimate applies.

   Option 2 may be used only where the measured string is in communication with the source zone. It may be used for an oil well only where the Reservoir Engineer documents why the reservoir behaves as a gas reservoir.

   The measurement must meet the following requirements:

   • The measurement must be taken by direct connection to the well, using a calibrated gauge, after transfer of the well to the Project Proponent and before the plug is set. Legacy gauges found in place must not be relied upon.
   • The well must remain shut in for a minimum of 24 hours and until pressure has stabilized, defined as a change of no more than 0.5% of the measured shut-in pressure or 0.5 psi, whichever is greater, per hour, sustained over four consecutive hours. The string measured and the full buildup record must be reported in the PDD.
   • Surface pressure must be converted to bottomhole pressure assuming a gas-only column, with no credit for wellbore liquids.
   • Before the measurement, the Project Proponent must document in the PDD the minimum bottomhole pressure needed to clear each threshold claimed, with all other inputs fixed. Where the measured pressure falls below that value, the threshold is not met.

   Method 2a: Volumetric estimation

   Remaining connected gas is estimated from the pore volume and gas saturation of the source zone at current reservoir pressure. Inputs must be supported as follows:

   • Drainage area must have a documented basis. It must not exceed the smaller of the regulatory spacing unit and the area defined by half the distance to the nearest offset well producing from the same zone.
   • Net pay, porosity and water saturation must be taken from logs or core from the well, or from a documented analogue in the same formation. Net pay must use stated cutoffs. Where the data indicate a range, the value producing the lower estimate must be used.

   Method 2b: Material balance

   Remaining connected gas is estimated from cumulative withdrawal (reported production plus gas leaked before T₀) and the decline from initial to current reservoir pressure. The following requirements apply:

   • This method must not be used where the source zone may be subject to material water influx or pressure support.
   • Initial pressure must be taken from documented well data. Where it is inferred from offset wells or a pressure gradient, the value producing the lower estimate must be used.

Remaining connected gas estimated under Section 8.3.1.3.1 is compared against the following thresholds:

(a) Basic threshold. Remaining connected gas must equal or exceed the volume implied by E₀ sustained at a constant rate over the full Crediting Period. Where it does not, [the well is ineligible for crediting / the cumulative baseline credited over the Crediting Period must not exceed remaining connected gas, and B_trajectory for later Reporting Periods is reduced accordingly].

(b) Rise-phase threshold. To elect the capped rise phase under Section 8.3.2.3, remaining connected gas must equal or exceed the volume implied by 1.25 × E₀ sustained at a constant rate over the full Crediting Period. Where it does not, Section 8.3.2.2 applies.

(c) Adjusted decline threshold. The threshold for the adjusted decline rate is set out in Section 8.3.2.1.

These thresholds are in addition to, and do not substitute for, the uncertainty discount applied to standoff measurements under Section 8.3.1.2.

8.3.1.3.3 Reservoir Engineering Qualifications

The Reservoir Engineer must hold a current Professional Engineer (PE) licence in the United States or a Professional Engineer (P.Eng.) licence in Canada, and must have demonstrated experience in reserves or resource estimation using the method(s) applied under Section 8.3.1.3.1 (decline curve analysis, volumetric estimation, or material balance).

$CO_2e_{Trajectory,\ RP}$ is the quantity of methane the well is projected to have emitted over the Reporting Period, expressed as CO₂e. It is obtained by integrating the baseline emissions trajectory established under 8.3.2.2 or 8.3.2.3 over the interval of the Reporting Period.

Because emissions from an orphaned well are not expected to remain constant indefinitely, this Section sets out how E(t) is projected forward to calculate $CO₂e_{Trajectory, RP}.$ The default treatment for all projects holds E₀ constant from T₀ through the end of Year 10 and applies terminal decline thereafter (Section 8.3.2.2). The plateau reflects two opposing mechanisms over the first decade. Depletion of the reservoir supplying the leak drives emissions down. Documented wellhead equipment corrosion makes it probable that leak pathways, and therefore emissions, will grow[^12]. At present, the predictive power of available models is insufficient for precise quantification of either effect[^13], and this Protocol therefore treats them as offsetting over the plateau period. A Project may elect a highly conservative capped rise phase in place of the plateau, but only where it meets additional evidentiary requirements, comprising a controlled flow measurement and characterization of the well’s corrosion environment (Section 8.3.2.3). Where those requirements are not met, Section 8.3.2.2 applies.

E(t) is expressed in MCF/d under Section 8.3.1. The trajectory is first calculated as a projected gas volume, then converted to a mass of methane, then to CO₂e:

$$CO_2e_{Trajectory,\ RP} = \left( \int_{RP} q(t) \, dt \right) \times \rho_{CH_4} \times GWP_{CH_4}$$

(Equation 6)

Where:

• $q(t)$ is the projected methane flow rate at time $t$ since T₀, in MCF/d, as defined by Equation 7 (default terminal decline) or Equations 9a–9c (capped rise phase), whichever trajectory applies under Section 8.3.2.2 or 8.3.2.3.
• $\rho_{CH_4}$ is the density of methane at the standard conditions defined in Section 8.3, in tonnes CH₄ per MCF (approximately 0.0192 t/MCF at 60 °F and 14.696 psia).
• $GWP_{CH_4}$ is the 100-year Global Warming Potential of methane from the most recent IPCC Assessment Report.
• The integral is evaluated over the interval of the Reporting Period (RP), in days.

The following default annual decline rates apply, segmented by emitter class. These rates are derived from the Payne Institute report and modified using the Payne Institute's P80/mean ratio (≈1.47x) applied to each class mean, to reflect a conservative (P80) rather than average expected decline[^5].

A well’s emitter class is determined by E₀ as finally established under Section 8.3.1, after any uncertainty discount applied under Section 8.3.1.2. The adjusted decline rate applies in place of the default rate for a well's emitter class where the reservoir volume estimate established under Section 8.3.1.3.1, using decline curve analysis or a shut-in pressure measurement, demonstrates remaining supply capacity at or above the cumulative volume implied by the adjusted decline curve over the full Crediting Period. Where the reservoir volume estimate indicates remaining capacity below this threshold, the default decline rate applies regardless of the method or combination of methods used to establish that estimate. This margin applies the same underlying supply-check principle used to establish eligibility for the capped rise phase under Section 8.3.2.3.

The Project Proponent must designate in the PDD which decline rate applies and provide the supporting reservoir volume estimate where the adjusted rate is claimed. Satisfying the reservoir supply threshold of Section 8.3.1.3.2 alone, without also clearing the adjusted curve's cumulative volume, does not entitle a Project to the adjusted decline rate.

$E_0$, established under Section 8.3.1, is held constant from T₀ through the end of the plateau period, ${T_P}.$ It is projected forward under a terminal decline curve thereafter. This is the default treatment for all projects. It applies regardless of whether E₀ was obtained by non-invasive measurement at the leak point under Section 8.3.1.1 or by standoff measurement under Section 8.3.1.2 (after application of the uncertainty discount), as both measure the as-found leak rate.

From the end of the plateau period, the Project Proponent must apply the default annual decline rate for the well’s emitter class set out in Section 8.3.2.1. Where the conditions of that Section are met, the adjusted decline rate applies instead.

$$E_{t} = E_0 (1 - D)^{\max(0,\, t - T_P)}$$

(Equation 7)

For example, consider a well with an initial baseline rate (E₀) of 100 MCF/d and an applicable annual decline rate (D) of 10%. It would be projected to emit 100 MCF/d through Year 10 and approximately 35 MCF/d at Year 20 (100 × 0.9¹⁰ ≈ 34.9). This reflects a cumulative decline of approximately 65% over the decline phase.

Where:

• E₀ is the baseline emission rate established at T₀ under Section 8.3, in MCF/d.
• ${D}$ is the applicable annual decline rate under Section 8.3.2.1 for the well’s emitter class.
• ${T_P}$ is the plateau period, fixed at 10 years.
• ${t}$ is time elapsed since T₀, in years.

A Project may elect to apply a capped rise phase in place of Section 8.3.2.2. To be eligible for the capped rise phase, E₀ must have been established under Section 8.3.1, by either non-invasive measurement at the leak point under Section 8.3.1.1 or standoff measurement under Section 8.3.1.2. Where standoff measurement was used, the rise phase must be applied to E₀ after the uncertainty discount in Section 8.3.1.2. Where any criterion is not met, Section 8.3.2.2 governs. The Project Proponent must designate the elected trajectory in the PDD and retain all eligibility evidence for verification.

The controlled flow measurement characterises how much the well could leak through an opening of a given size. It does not measure the as-found leak rate. Instead, it provides the controlled flow rate $E_{CF}$ which represents the rate at which the well would emit if corrosion enlarged its leak path to the tested choke opening. It is obtained by connecting to the wellhead and opening a choke to establish controlled, stable flow and should be used with a corrosion model to estimate the amount a well could deliver by following projected corrosion on the wellhead. The corrosion model must be chosen in agreement with Isometric and must be applied using four points; flow rate, pressure, temperature and pCO₂.

$E_{DC}$ is then used to convert the resulting corrosion rate into an implied linear annual rise rate relative to E₀:

$r_{CM} = (E_{CF} / E_{0} - 1) \times (CR / d_{choke})$

(Equation 8)

Where:

• $r_{CM}$ is the implied linear annual rise rate relative to E₀.
• $E_{CF}$ is the controlled flow rate, in MCF/d.
• $E_{0}$ is the baseline emission rate under Section 8.3.1, in MCF/d.
• $CR$ is the corrosion rate output by the corrosion model, in mm/yr.
• $d_{choke}$ is the choke size used in the controlled flow measurement, in mm.

The Project Proponent must document the model applied, the input values and their sources, and the derivation of $r_{CM}$in the PDD.

The rise phase runs for up to 10 years from T₀. Over this period, emissions rise linearly at the applicable rise rate, to a maximum of 1.25× E₀. This is a capped, non-compounding total increase of 25%, equivalent to 2.5% of E₀ per year. After Year 10, the terminal decline treatment of Section 8.3.2.2 applies, calculated from the Year 10 peak value.

Rise phase (0 ≤ t ≤ 10):

$q(t) = E_{0} \times (1 + r_{rise} \times t)$

(Equation 9a)

where:

$r_{rise} = r_{CM}$, where $r_{CM}$< 0.025
$r_{rise}$ = 0.025, where $r_{CM} \geq$ 0.025

In these terms:

• $r_{CM}$ is the implied linear annual rise rate under Equation 8.
• 0.025 is the maximum annual rise rate, which gives the 25% total rise cap over 10 years when distributed linearly.
• E₀ is the baseline emission rate established at T₀ under Section 8.3.1, in MCF/d. Where standoff measurement was used, this is the value after the uncertainty discount.
• t is time elapsed since T₀, in years.

Decline phase (t > 10):

$q(t) = q_{peak} \times (1 - d)^{t - 10}$

(Equation 9b)

$q_{peak} = E_{0} \times (1 + 10 \times r_{rise})$

(Equation 9c)

In these terms:

• $q_{peak}$ is the Year 10 peak value, from which the terminal decline treatment of Section 8.3.2.2 resumes. It equals 1.25× E₀ where the cap binds, and is lower where $r_{CM}$ governs.
• $d$ is the applicable annual decline rate under Section 8.3.2.1, applied from the Year 10 peak onward.
• $t$ is time elapsed since T₀, in years.

$CO_2e_{Counterfactual,\ RP}$ is the portion of the projected baseline emission that would have been avoided regardless of the Project. For a Project under this Protocol, this arises in only one circumstance: where the well would have been plugged under an existing state, provincial or federal program in the absence of Project intervention, such that some part of the projected trajectory would not have been emitted even had the Project not proceeded.

This term is retained to make explicit that the possibility of publicly funded plugging has been considered in the baseline, rather than assumed away. In practice, it is expected to be zero for all Projects, because the circumstance that would give rise to a non-zero value is excluded at the point of eligibility rather than adjusted for in the quantification:

• Section 4.4 excludes wells slated to be plugged by state authorities.
• Section 4.3 requires documented confirmation that measured leaks have been reported and that the well was not scheduled for imminent government plugging, together with correspondence from the relevant authority that the well is not currently and will not be prioritised for plugging using state or federal funds.
• Section 5.4 requires that a Project be treated as ineligible where the financial and regulatory additionality assessment shows the well would have been plugged absent Carbon Finance, including where public funding alone would have been sufficient.

The project term is:

$$CO_2e_{Project,\ RP} = CO_2e_{Establishment,\ RP} + CO_2e_{Operations,\ RP} + CO_2e_{End\text{-}of\text{-}life,\ RP}$$

(Equation 10)

Where:

• $CO_2e_{Establishment,\ RP}$ represents GHG emissions associated with Project establishment, occurring before the Reporting Period, in tonnes CO₂e (Section 8.4.1).
• $CO_2e_{Operations,\ RP}$ represents the GHG emissions associated with Project operations, occurring during the Reporting Period, in tonnes CO₂e (Section 8.4.2).
• $CO_2e_{End\text{-}of\text{-}life,\ RP}$ represents GHG emissions anticipated to occur after the Reporting Period and allocated to it, in tonnes CO₂e (Section 8.4.3).

The following sections set out specific quantification requirements for each variable.

GHG emissions associated with Project establishment must include all emissions incurred in establishing the Project, including but not limited to the SSRs set out in Table 1. Substantially all physical Project activity under this Protocol occurs within a single window around the plugging event. Therefore, $CO_2e_{Establishment,\ RP}$ comprises all activities associated with:

• site preparation
• baseline measurement campaign, including any controlled flow measurement under Section 8.3.2.3
• any direct emissions from well intervention
• well preparation and plugging
• removal of legacy equipment and site reclamation

Establishment emissions may be accounted for in the following ways, with the allocation method selected and justified by The Project Proponent:

• as a one-time deduction from the first verification, or
• amortized over the first crediting period (or less) as annual emissions.

Amortization is available only where The Project Proponent has elected the annual ex-post release schedule under Section 8.1. Where the phased time-integrated release schedule is elected, establishment emissions must be accounted for as a one-time deduction from the first verification.

GHG emissions associated with $CO_2e_{Operations,\ RP}$ must include all emissions associated with operational activities occurring during the Reporting Period, including but not limited to the SSRs set out in Table 1. For a Project under this Protocol, these comprise activities associated with the post-plug permanence checks required under Section 9.1, and replugging the well, where a permanence check measures non-zero Project methane emissions.

$CO_2e_{Operations,\ RP}$ emissions must be attributed to the Reporting Period in which they occur.

$CO_2e_{End\text{-}of\text{-}life,\ RP}$ includes all emissions associated with activities that are anticipated to occur after the Reporting Period, but are directly or indirectly related to it, including but not limited to the SSRs set out in Table 1. For a Project under this Protocol these comprise the anticipated end-of-life emissions of any infrastructure or equipment established by The Project.

GHG emissions associated with the post-plug permanence checks are directly related to the deployment being credited and must be estimated upfront and quantified as part of that Reporting Period. GHG emissions associated with activities that are indirectly related to all deployments may be allocated in the same ways as set out in $CO_2e_{Establishment,\ RP}$, subject to the same restriction on amortization.

Project Proponents must use the most representative, accurate, and plausible data that is available at the time of assessment in the GHG Statement. Activity data used to inform GHG accounting may be primary data or secondary data. Project Proponents must strive to use primary data in GHG accounting, but secondary data may be used where primary data is not available, not practical, or the emission source accounts for < 1% of net reduction. More details on data requirements can be found in Section 3 of the GHG Accounting Module v1.1.

Project Proponents may exclude any SSRs included in Table 1 from the final net reduction quantification if these are demonstrated to be negligible. Negligible SSRs are those that fall below a Materiality threshold based on an environmental significance of less than 1% of net CO₂e reduction in any given Reporting Period. The sum of negligible SSRs must not be equal to or more than 1% of the net reduction.

To demonstrate this, Project Proponents may utilize an economic input-output (EEIO) approach as a preliminary screening test, estimating emissions based on project financial data (e.g., CAPEX data) combined with EEIO emission factors. If this screening demonstrates that emissions are below the Materiality threshold, emissions can be excluded or can be estimated using high-level estimations if included. See Section 5.0 of the Isometric GHG Accounting Module v1.1 for more details on the approach and example libraries.

Alternatively, where financial data is unavailable, Project Proponents may use other benchmarks to estimate emissions. For example, proponents may rely on physical benchmarks from industry-standard life cycle inventory databases based on activity-level parameters relevant to similar sectors.

Ancillary activities, such as supplementary research and development activities and corporate administrative activities, that are associated with a Project but are not directly or indirectly related to the issuance of Credits can be excluded from the system boundary.

This section sets out specific requirements relating to quantification of energy use as part of the GHG Statement. Emissions associated with energy usage result from the consumption of electricity or fuel. For a Project under this Protocol, fuel consumption is expected to dominate and grid electricity consumption is expected to be immaterial or absent.

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

• diesel consumed by the workover rig, cement pump, blender and compressors during wellbore preparation, cement placement and pressure testing;
• diesel or petrol consumed by earthmoving and construction plant during access track construction, pad clearance, regrading and reclamation;
• fuel consumed by portable generators, light towers and welfare units at the wellsite;
• fuel or electricity consumed by measurement equipment, including fans, pumps and analysers, during each measurement event;
• fuel consumed by cutting torches and mechanical cutters during casing cut-off and equipment removal.

Section 6 of the Energy Use Accounting Module v1.3 provides requirements on how fuel-related emissions must be calculated in a Project.

Project electricity consumption emissions must be calculated using the following calculation approach:

$$CO_2e_{EC,\ RP} = (EC_{grid,\ RP} \times EF_{grid,\ RP} \times (1+f_{TD\text{-}losses,\ RP})) + (EC_{generator,\ RP} \times EF_{generator,\ RP})$$

(Equation 11)

Where:

• $CO_2e_{EC,\ RP}$ represents total emissions from the project's electricity consumption over the Reporting Period, RP, in tonnes CO₂e.
• $EC_{grid,\ RP}$ represents the total electricity consumed from the grid over the Reporting Period, RP, in kWh.
• $EF_{grid,\ RP}$ represents the emission intensity of the electricity grid over the Reporting Period, RP, in kg CO₂e/kWh.
• $f_{TD\text{-}losses,\ RP}$ represents the transmission and distribution grid losses factor.
• $EC_{generator,\ RP}$ represents the total electricity consumed from a non-grid generator over the Reporting Period, RP, in kWh.
• $EF_{generator,\ RP}$ represents the emission factor associated with the non-grid generator, in kg CO₂e/kWh.

Project Proponents may determine the emission intensity of the electricity grid, $EF_{grid,\ RP}$, using the following hierarchy:

• Projects may use Combined Margin (CM) emission factors from a reputable source. The suitability and technical rigor of the selected CM factor and its source will be evaluated by Isometric on a case-by-case basis during project validation.
• If appropriate CM factors are not available for the location of The Project, the Project Proponent must apply one of the following default values for $EF_{grid,\ RP}$, based on the share of renewable and nuclear energy in the electric grid:
  • 1.3 kg CO₂e/kWh if the share of renewables and nuclear is less than or equal to 33%;
  • 0.87 kg CO₂e/kWh if the share of renewables and nuclear is between 33% and 67%;
  • 0.44 kg CO₂e/kWh if the share of renewables and nuclear exceeds 67%.

If the generation source is a captive fossil fuel-fired power plant, Projects should make every attempt to gather information on the emission intensity of the technology generating the electricity. Where a specific emission intensity is not available, Projects must apply a default of 1.3 kg CO₂e/kWh.

Projects may determine the transmission and distribution grid losses factor using the following hierarchy:

• Projects may use transmission and distribution grid losses factors from a reputable source;
• If transmission and distribution grid losses factors are not available for the location of the Project, it is set at 25% for all Projects.

This section sets out specific requirements relating to the quantification of embodied emissions as part of the GHG Statement. Embodied emissions are those related to energy use or other emissions during the manufacture of equipment and materials used in a process.

Examples of project-specific materials and equipment that must be considered as part of the embodied emission calculation include, but are not limited to:

• oilwell cement, reported by class, and cement additives, extenders and dispersants, reported separately;
• mix water, brine and other completion fluids;
• aggregate, matting and drainage materials used in temporary access construction;
• measurement and detection equipment, including enclosures, analysers, flow meters, pressure instrumentation and standoff survey equipment;
• seed, soil amendments and other reclamation materials.

The GHG Accounting Module v1.1 sets out the approach to be followed to account for embodied emissions, including life cycle stages to be considered (Section 4.1), and data sources and emission factors (Section 3.3).

No reduction in embodied emissions may be claimed for the reuse, resale or recycling of legacy surface equipment recovered from the wellsite.

This section sets out specific requirements relating to quantification of transportation emissions as part of the GHG Statement. Examples include, but are not limited to:

• mobilisation and demobilisation of the workover rig, pump truck, bulk cement truck and water truck;
• delivery of cement, additives, water, aggregate and reclamation materials to the wellsite;
• delivery and collection of measurement and monitoring equipment for each measurement event and each post-plug permanence check;
• haulage of recovered equipment, produced fluids, contaminated soil and other waste from the wellsite;
• air, road and rail travel of staff, contractors and third-party assessors required on site.

Section 4.2 of the GHG Accounting Module v1.1 provides requirements on how transportation emissions must be calculated for Projects.

Reversals are defined as plug structural defects that may result in emissions of CH₄ to the atmosphere. Plugged wells that meet modern API RP 65-3 standards are considered to have high structural permanence. However, the possibility of reversals exists. The likelihood and severity of disturbances are influenced by external and project-related factors.

Project-related factors:

• Well barrier durability

External factors:

• Geological stressors
• Seismic shifts
• Thermal stress
• Chemical stress

Post-plug permanence checks are required for every Project, regardless of the credit release schedule elected under Section 8.1. The first permanence check must occur within the month 12–18 window following plugging. Where a permanence check measures non-zero Project methane emissions, the Project Proponent must recommence plugging activities and perform a subsequent verification test within a following 12–18 month window.

Permanence checks must use a non-invasive method permitted under Section 8.3.1.1, conducted by a measurement specialist meeting the same requirements. A permanence check confirms zero Project methane emissions where no methane emission is detected above the method detection limit of the instrument used.

The consequence of a permanence check result differs by credit release schedule, as follows:

• Phased time-integrated release. Credit issuance is tied to performance. Following successful initial Project validation, 80% of total credits are released. The remaining 20% is released only after the month 12–18 permanence check confirms zero Project methane emissions. Where that check measures non-zero emissions, the remaining 20% is withheld pending the outcome of the subsequent verification test required above. Where that subsequent test measures zero Project emissions, the remaining 20%, minus any emissions from the second plugging activity, is released. Where it again measures non-zero emissions, the withholding and re-test cycle continues until a permanence check confirms zero Project emissions.
• Annual ex-post release. Because credits are issued only following each successive verification event, the month 12–18 permanence check ordinarily coincides with the Reporting Period 1 verification event, and no separate release gate is required. Where that check measures non-zero Project methane emissions, the measured emissions are accounted for. Credits already issued for prior Reporting Periods are not retroactively adjusted. The Project Proponent must recommence plugging and complete the subsequent verification test as required above, with any resulting emissions similarly accounted for as Project emissions in the Reporting Period in which the re-test occurs.

Both schedules remain subject to the same underlying permanence check requirement and re-plugging obligation; the difference is procedural, in how a non-zero result is reflected in the timing and quantity of Credit issuance, rather than in the substantive monitoring standard applied.

This section establishes monitoring and documentation requirements necessary to ensure the accuracy, completeness, and credibility of orphaned well methane reduction projects.

Requirements are grouped based on asset type. Orphaned well projects use the following assets:

• Wells (baseline measurement, safety assessment and standoff measurement, controlled flow measurement, and reservoir supply evidence)
• Plugging Operations and Site Records
• Post-Plug Monitoring Infrastructure
• Ownership and Rights Records

Requirements are further organised into two categories:

• Validation requirements include evidence and documentation required at initial project registration.
• Verification requirements include ongoing evidence to be submitted for each Reporting Period.

Requirements are grounded in the following principles:

• Measurement Accuracy: The T₀ baseline measurement, E₀, is the sole measured determinant of the baseline level for the full Crediting Period (Section 8.3.1, Section 8.3.2); where the capped rise phase is elected, the controlled flow measurement, $E_{DC}$, additionally determines the rate of rise (Section 8.3.2.3). Because no further direct measurement of the counterfactual leak occurs after plugging, errors or bias in this single measurement propagate across the entire crediting horizon, making instrument accuracy, sampling procedure, and stability verification especially consequential.
• Safety and Reservoir Evidence Traceability: Where a well departs from the default measurement or trajectory treatment, either through standoff measurement (Section 8.3.1.2) or an elective capped rise phase (Section 8.3.2.3), the underlying third-party safety assessment, controlled flow measurement, corrosion model inputs, and reservoir supply evidence must be independently traceable and auditable, since these determinations materially affect the credited quantity.
• Permanence Verification: Post-plugging emissions must be independently verifiable through scheduled monitoring events, to confirm that the baseline emission has been durably addressed.

Validation Requirements

• The project must provide the well's location (GPS coordinates), well identification, and documentation establishing its status as an orphaned well under Section 4.3.
• The project must describe the measurement pathway used (non-invasive measurement at the leak point or standoff measurement) in accordance with Section 8.3.1.1 or 8.3.1.2., including instrument selection, accuracy specifications, and calibration procedures
• The project must document the sampling plan, including measurement interval, sampling duration, and the applicable environmental exclusion criteria (Sections 8.3.1.1.1–8.3.1.1.2) or, for standoff measurement, the equivalent sampling design for the method used
• Where a well is classified as a large or super-emitter under Section 8.3.1.1.4, the project must describe the additional stability testing protocol to be applied.

Verification Requirements

• The project must provide raw measurement data from each sampling event, including timestamps, individual readings, and, for measurement under Section 8.3.1.1, the coefficient of variation across the 12-measurement set (Section 8.3.1.1.2).
• Where standoff measurement is used, the project must document the uncertainty discount applied and its basis, and E₀ before and after application of the discount (Section 8.3.1.2)
• The project must provide instrument calibration and verification records for the equipment used at T₀.
• The project must document the resulting $E_0$ value and the calculation method used to derive it from the underlying measurements (Section 8.3.1.1.2, 8.3.1.1.3, 8.3.1.1.4).
• The project must confirm that the measurement was not taken during an excluded environmental condition, or document the conditions if an exclusion applies.

Validation Requirements

• Where standoff measurement is used, the project must provide the signed third-party safety assessment required under Section 8.3.1.2.1, including the outcome category, the record of each assessment indicator under Section 8.3.1.2.1.2, and dated and geo-tagged photo or video evidence of observed conditions.
• The project must document the assessor's qualifications and independence under Sections 8.3.1.2.1.4 and 8.3.1.2.1.5, with supporting evidence.
• Where a Category 2 outcome was returned, the project must provide the second assessor's review. For a Category 3 outcome, the project must provide the well control and equipment plan.
• The project must document the standoff method used and the proposed uncertainty discount, together with its supporting literature basis, as agreed with Isometric (Section 8.3.1.2).

Verification Requirements

• The project must provide raw standoff measurement data, including all inputs to any dispersion or plume model used, and the calculation of E₀ before and after application of the uncertainty discount.

10.1.3 controlled flow measurement (Capped Rise Phase)

Validation Requirements

• Where the capped rise phase is elected, the project must describe the controlled flow measurement arrangement and the corrosion model selected in agreement with Isometric (Section 8.3.2.3).
• For wells assessed under Category 3, the project must confirm that the controlled flow measurement is covered by the well control and equipment plan.

Verification Requirements

• The project must provide the recorded controlled flow rate, $E_{CF}$, the choke size used, and evidence that controlled, stable flow was established.
• The project must confirm that E₀ was established before the controlled flow measurement was taken.
• The project must document the corrosion model inputs (temperature, pressure, CO₂ mole percent) and their sources, the corrosion rate output, the derivation of $r_{CM}$ under Equation 8, whether the 0.025 cap binds, and the resulting Year 10 peak value, $E_{peak}$.

Validation Requirements

• The project must document the decline curve analysis performed under Section 8.3.1.3.1(1), including the decline model applied, the parameters used, the basis for their selection, and confirmation that the analysis was conducted or reviewed by a qualified reservoir engineer.
• The project must provide the historical production record used, including confirmation that the final 24 months of production prior to orphaning were excluded, and, where available, the completion records used to confirm producing zone(s).
• The project must provide the shut-in pressure measurement obtained under Section 8.3.1.3.1(2), including instrumentation used and confirmation that it was obtained via direct connection solely for this purpose (not a legacy in-place gauge reading).

Verification Requirements

• The project must provide the resulting reservoir volume estimate and its comparison against the applicable threshold(s): the basic supply threshold (Section 8.3.1.3.2), and, where the adjusted decline rate or capped rise phase is claimed, the corresponding 2x margin threshold.
• The project must document any material inconsistency identified between the shut pressure measurement and the decline-curve-derived volume estimate (Section 8.3.1.3.1(2)).

Validation Requirements

• The project must describe the planned plugging procedure, including confirmation of compliance with applicable state or provincial plugging permit requirements.
• The project must document the pre-plugging condition of the well site, for use in confirming post-plugging restoration (Section 6.4.2).

Verification Requirements

• The project must confirm that plugging was completed in accordance with the applicable state or provincial permit, including the date of completion and any inspection or sign-off records from the relevant regulatory authority.
• The project must provide records of produced water, brine, or other fluid and material disposal undertaken during plugging (Section 6.4.1).
• The project must confirm site restoration following plugging, including comparison against the documented pre-plugging condition (Section 6.4.2).
• The project must document any unrelated contamination discovered during plugging and its disclosure to the relevant regulatory authority (Section 6.4.3), where applicable.

Validation Requirements

• The project must describe the post-plug monitoring plan, including the schedule of permanence checks to be conducted (Section 9.1) and the credit release schedule elected (phased time-integrated or annual ex-post, Section 8.1).

Verification Requirements

• The project must provide results of each scheduled post-plug permanence check, including measured emission rate (if any) and instrumentation used.
• Where an unanticipated leak is discovered outside a scheduled permanence check, the project must document the discovery, the measured leak rate, and its treatment as a reversal under Section 9.1.

Validation Requirements

• The project must document the chain of ownership from the surface owner through to the Project Proponent's operating rights, including landowner permission for site access and measurement, and the relevant state or provincial transfer instrument (Section 5.3).
• Where infrastructure such as new or upgraded access roads is required to support the Project, the project must document landowner consent specific to that infrastructure (Section 6.3).

Verification Requirements

• The project must confirm that ownership and operating rights remain valid and unchanged for the Reporting Period, or document any transfer that occurred.

Validation Requirements

• The project must provide all required documentation establishing financial additionality as described in Section 5.4, including the financial additionality assessment and, where applicable, documentation addressing the interaction between Carbon Finance and any state or federal plugging funding.
• The project must provide all required documentation establishing regulatory additionality as described in Section 5.4, including evidence that the well is not subject to a legal or regulatory obligation requiring it to be plugged absent the Project, and documentation of the relevant state plugging rate or funding penetration used to assess it.

To ensure consistency and accuracy, the project must perform the following reconciliation checks at each verification:

• The project must reconcile the E₀ value used in the Reporting Period's trajectory calculation with the underlying T₀ measurement records (Section 10.1.1), including, for standoff measurement, the application of the uncertainty discount (Section 8.3.1.2)
• The project must confirm the decline rate or rise-phase treatment applied is consistent with the eligibility evidence documented under Sections 8.3.1.3 and 8.3.2.3, including, where applicable, the controlled flow measurement and corrosion model record under Section 10.1.3.
• The project must confirm the credited quantity for the Reporting Period is consistent with the credit release schedule elected in the PDD (Section 8.1).

The project must document discrepancies identified during reconciliation, and take corrective action before Credits are issued for the affected Reporting Period.

Table A1. Baseline Measurement Monitoring Requirements by Measurement Pathway

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