PCS MT 001 Carbon Capture & Storage_v1.0
Document Control
Document identification
Document code: PCS-MT-001
Title: Modular Methodology for CO₂ Capture, Transport, and Geological Storage (CCS)
Scope: CCS activities involving CO₂ capture, transport, and permanent geological storage using a modular structure (Module A: Capture; Module B: Transport; Module C: Geological Storage), subject to applicability conditions and PCS requirements
Crediting outcome: Net climate benefit expressed as Planetary Carbon Credits (PCCs), representing quantified net emission reductions and/or removals resulting from CCS activities, after accounting for project emissions and leakage, consistent with PCS rules
Version history and change log
Table DC-1. Revision history
v1.0
TBD
Draft
Initial release for public consultation
PCS
TBD
Superseded versions
No superseded versions for v1.0.
Governance note on versioning and archiving
Only the latest approved version of this methodology and its modules shall be used for new project registrations. Superseded versions shall be archived and retained for traceability and audit purposes, including for projects registered under earlier versions where applicable, consistent with PCS governance rules.
Purpose and scope summary
Purpose
This methodology establishes requirements and procedures to quantify net climate benefit from project activities involving the capture, transport, and permanent geological storage of CO₂, using a modular structure that supports different CCS configurations while maintaining methodological rigor and environmental integrity.
Scope summary
This methodology applies to CCS project activities that permanently store CO₂ in suitable geological formations and meet PCS requirements for monitoring, quantification, leakage management, safeguards, and long-term stewardship. The methodology is structured into the following technical modules, applied as relevant to the project configuration:
Module A - CO₂ Capture (PCS-MT-001-A): capture and processing of CO₂ from eligible sources
Module B - CO₂ Transport (PCS-MT-001-B): movement of CO₂ by pipeline, ship, rail, or truck
Module C - Geological Storage (PCS-MT-001-C): injection and storage of CO₂ in geological formations for permanent storage
Activities outside the stated scope of the modules, and configurations that do not meet PCS integrity and monitoring requirements, are not eligible unless explicitly addressed by PCS through an approved deviation or a later methodology update.
Methodology overview (how the quantification works)
Quantification is conducted ex-post for each monitoring period using monitored data and conservative methods. Net credited outcome is calculated from the climate benefit of captured and permanently stored CO₂, minus all relevant emissions associated with capture, transport, and injection, and minus any leakage (including unintended releases) as determined under the monitoring and leakage provisions. Monitoring, data retention, and liability requirements extend through the crediting period and the post-injection monitoring period, consistent with PCS governance and permanence rules.
Normative references
The following documents are normative for application of this methodology. Where there is a conflict, the higher-level PCS governing document prevails unless PCS explicitly states otherwise.
Table NR-1. Normative references
PCS Framework v2.0
PCS Framework
Program principles and governance hierarchy
PCS Operational Process Manual
Program Manual / operational processes
Operational requirements and procedures
PCS MRV & Safeguards Standards
MRV and safeguard requirements
Integrity and monitoring expectations
PCS Methodology Development and Revision Procedure
Methodology governance
How revisions, clarifications, and updates are handled
PCS Grievance and Appeal Procedure
Grievance & appeals
Complaints, disputes, and governance recourse
PCS VVB Accreditation & Approval Procedure
VVB approval
Assurance system requirements
IPCC 2006 Guidelines
National GHG Inventories
Baseline and accounting guidance
IPCC 2019 Refinement
Refinement to 2006 Guidelines
Updated factors and accounting guidance
IPCC SRCCS
Special Report on CCS
CCS-specific technical and MRV guidance
ISO 27914
Geological storage standard
Storage site selection, operation, and monitoring framework
ISO 27916
Quantification and verification
Quantification, monitoring, and verification framework
IEA CCS Roadmap
CCS Technology Roadmap
Best practice and context
CSLF Guidelines
Technical guidelines
Best practice for CCS design and MRV
Terms, definitions, and abbreviations
Terms and definitions used in this methodology are provided in Chapter 2, together with abbreviations for consistent use across project documentation, monitoring reports, and verification reports.
Applicability statement and exclusions
Detailed applicability conditions and excluded activities are provided in Chapter 1 and the module-specific scope sections. Requirements on boundary, baseline, additionality, quantification, monitoring, leakage, uncertainty/conservativeness, safeguards, and verification/validation are defined across the core chapters and the applicable modules.
Chapter 1 - Introduction And Scope
1.1 Purpose of the Methodology
Purpose
The purpose of this modular methodology is to establish a comprehensive framework for the quantification of emission reductions and removals resulting from project activities involving the capture, transport, and geological storage of carbon dioxide. The methodology provides a consistent, transparent, and scientifically robust structure that enables diverse CCS projects to generate high-integrity Planetary Carbon Units under the Planetary Carbon Standard (PCS). By adopting a modular design, PCS accommodates a range of CCS technologies and project configurations while maintaining methodological rigor and environmental integrity.
Background and Rationale
Carbon Capture and Storage (CCS) is a critical climate mitigation pathway recognized by IPCC, IEA, ISO, and national strategies. CCS enables permanent geological sequestration of CO₂ from large point sources (industrial facilities, hydrogen production, waste-to-energy plants, fossil energy systems). Harmonized quantification rules are essential to ensure CCS activities yield real, measurable, long-term climate benefits. This methodology consolidates best practices from international standards, engineering guidance, geological assessment frameworks, and lifecycle accounting principles to ensure defensible emission reduction estimates.
Modular Structure
All projects must apply the PCS-MT-001 Core Module (baseline, additionality, system boundaries, reporting). Project developers shall apply one or more technical modules according to configuration:
Module A — CO₂ Capture (PCS-MT-001-A)
Module B — CO₂ Transport (PCS-MT-001-B)
Module C — Geological Storage (PCS-MT-001-C)
Each module contains monitoring requirements, quantification equations, data parameters, and leakage provisions.
1.4 Applicability of the Methodology
This methodology applies to project activities that permanently store anthropogenic CO₂ in deep geological formations. It covers CO₂ captured from industrial point sources, processed and compressed for transport, and injected into reservoirs with suitable caprock and long-term containment characteristics. The methodology applies to saline formations, depleted oil and gas reservoirs, and other geological systems that meet PCS site characterization requirements. Enhanced Oil Recovery (EOR) projects may apply the methodology only when net geological storage can be demonstrated.
1.5 Activities Excluded from this Methodology
This methodology does not apply to biological carbon storage, enhanced weathering, ocean fertilization, mineralization ex situ, or projects without permanent storage. Projects involving CO₂ utilization must apply separate PCS methodologies unless the utilization process results in demonstrable geological storage consistent with Module C.
1.6 Environmental Integrity and Safeguard Considerations
All CCS projects shall adhere to PCS safeguard requirements. This includes demonstrating site characterization per international best practices, minimizing risks of leakage and environmental harm, and deploying monitoring plans consistent with PCS MRV requirements. The methodology integrates geological risk management, long-term containment considerations, and post-injection stewardship into quantification requirements.
1.7 Relationship to PCS Framework and Other PCS Procedures
This methodology must be applied in conjunction with:
PCS Framework v2.0
PCS Operational Process Manual
PCS MRV & Safeguards Standards
PCS Methodology Development and Revision Procedure
PCS Grievance and Appeal Procedure
PCS VVB Accreditation & Approval Procedure
In the event of a discrepancy, the PCS Framework v2.0 takes precedence.
1.8 Transparency, Traceability, and Reporting
All calculations, assumptions, monitoring results, and model outputs must be documented transparently. Data must be traceable, verifiable, and supported by evidence. Projects shall maintain records for the full crediting period and post-injection monitoring period.
Chapter 2 - Normative References And Definitions
2.1 Purpose of This Chapter
This chapter establishes the normative references, definitions, and terminology required for consistent interpretation and application of this methodology. CCS projects involve complex engineering, geoscience, and monitoring processes. Clear definitions ensure that Project Developers, Validation and Verification Bodies (VVBs), host country authorities, and the PCS Secretariat apply the methodology in a consistent manner.
2.2 Normative References
The following documents are integral to the application of this methodology. For dated references, only the edition cited applies. For undated references, the most recent edition (including any amendments) applies.
a) Intergovernmental Panel on Climate Change (IPCC)
IPCC 2006 Guidelines for National Greenhouse Gas Inventories
IPCC 2019 Refinement to the 2006 Guidelines
IPCC Special Report on Carbon Dioxide Capture and Storage (SRCCS)
These references guide baseline establishment, emissions accounting, and leakage assessment.
b) ISO Standards for CCS
ISO 27914 — Carbon dioxide capture, transportation and geological storage — Geological storage
ISO 27916 — Carbon dioxide — Quantification and verification of CO₂ capture, transport and geological storage
ISO standards provide authoritative frameworks for measurement, modeling, and monitoring.
c) International Energy Agency (IEA) & CSLF Guidance
IEA CCS Technology Roadmap
Carbon Sequestration Leadership Forum (CSLF) Technical Guidelines
These documents contribute to best practices in site selection, risk assessment, and MRV.
d) PCS Governance Documents
This methodology must be read alongside the following PCS documents:
PCS Framework v2.0
PCS Operational Process Manual
PCS Safeguard Requirements
PCS VVB Accreditation & Approval Procedure
PCS Methodology Development and Revision Procedure
Where conflicts arise, the PCS Framework v2.0 prevails.
e) National and Regional CCS Regulations
Projects must comply with host country regulations on subsurface storage, well integrity, health and safety, and monitoring and closure obligations. National rules do not replace PCS requirements; both must be met.
2.3 Definitions
The following definitions apply to all modules within PCS-MT-001 unless otherwise specified.
2.3.1 Carbon Dioxide (CO₂)
Carbon dioxide captured from anthropogenic sources, compressed, transported, and injected for permanent geological storage.
2.3.2 CCS Project
A project activity involving one or more of the following:
Capture of CO₂ from industrial or energy-related sources
Transport of compressed CO₂
Injection and permanent storage in geological formations
Projects may include one, two, or all three modules depending on configuration.
2.3.3 Permanent Geological Storage
The long-term containment of CO₂ in a geological formation with robust trapping mechanisms, such that the stored CO₂ is not expected to migrate to the atmosphere under foreseeable conditions. Includes structural, residual, solubility, and mineral trapping.
2.3.4 Storage Site
A subsurface geological formation selected for CO₂ injection and long-term containment, characterized by suitable reservoir properties, adequate caprock integrity, demonstrated storage capacity, acceptable geological risk levels, and compliance with PCS site characterization requirements.
2.3.5 Storage Complex
A geological system that includes the storage reservoir, confining layers, lateral and vertical boundaries, and secondary containment formations. Used for leakage modeling and MRV design.
2.3.6 Capture Facility
A facility that separates CO₂ from industrial or energy-related gas streams using physical, chemical, or biological processes (e.g., amine scrubbing, solvent/sorbent systems, membranes, cryogenic separation, oxyfuel combustion).
2.3.7 Transport System
Infrastructure used to convey CO₂ to the injection site, including pipelines, ships, trucks or rail, compression stations, booster and recompression equipment.
2.3.8 Injection System
Wells and associated equipment used to deliver CO₂ to the geological formation (injection wells, wellbore tubings, wellhead equipment, packers and seals, surface monitoring stations).
2.3.9 Leakage
Any unintended release of CO₂ from the capture, transport, or storage system into the atmosphere, groundwater, surface water, or shallow geological formations. Leakage is assessed at all CCS stages.
2.3.10 Baseline Scenario
A counterfactual scenario representing emissions that would occur in the absence of the CCS project. The baseline for storage projects assumes zero storage and continuation of existing emissions from the capture source.
2.3.11 Additionality
Demonstration that the CCS project is not mandated by law, is not already financially viable without carbon revenue, and would not occur under business-as-usual conditions.
2.3.12 Monitoring, Reporting, and Verification (MRV)
A structured set of procedures used to measure key CO₂ quantities, track system performance, ensure detection of leakage, and verify reported data. MRV systems must be consistent with PCS MRV requirements.
2.3.13 Net Stored CO₂
The amount of CO₂ stored in the geological formation after subtracting indirect emissions, leakage emissions, energy-related emissions, and transport-related losses. This value is used for PCU issuance.
2.3.14 Post-Injection Monitoring Period
The period after cessation of CO₂ injection during which the project must continue monitoring to ensure long-term containment.
2.3.15 Corrective Measures Plan
A mandatory plan describing actions to be taken in the event of leakage, pressure anomalies, well integrity failure, or other risks to permanent containment.
2.3.16 Validation and Verification Body (VVB)
An accredited and approved independent body responsible for validating CCS project design and verifying monitoring results and emissions calculations.
2.3.17 Project Boundary
The physical and process-related elements included in the calculation of emission reductions (capture unit(s), transport infrastructure, injection wells, storage reservoir, MRV monitoring area, all leakage pathways).
2.3.18 Responsible Entity
The legal entity accountable for CO₂ containment, monitoring, and liability throughout the crediting and post-injection period.
Chapter 3 - Applicability Conditions
3.1 Purpose of Applicability Conditions
Applicability conditions define the boundaries within which this methodology may be used and ensure that the project activity is suitable for quantification of emission reductions under PCS. These conditions protect methodological integrity, prevent inappropriate use, and ensure that quantification is scientifically defensible.
3.2 Eligible Project Activities
This methodology applies to activities involving capture of anthropogenic CO₂ from industrial or energy-related point sources, transport to a storage site, and permanent geological storage. Projects must apply the Core methodology and relevant technical modules. The methodology is applicable only when CO₂ is intended for permanent storage and when PCS requirements for site characterization and risk assessment are met.
3.3 Origin of CO₂ and Eligible Capture Sources
This methodology applies exclusively to anthropogenic CO₂ from industrial or energy-related processes (power generation, cement, steel, ammonia/urea, petrochemical/hydrogen production, refineries, waste-to-energy). CO₂ from biogenic sources may be included only with additional safeguards. Direct air capture is excluded and requires a separate methodology.
3.4 Requirements for Geological Storage Sites
Projects must inject CO₂ into deep formations capable of permanent containment (saline aquifers, depleted reservoirs, basaltic formations, etc.). Sites must undergo thorough characterization (geological, geophysical, hydrogeological, geochemical, geo-mechanical), demonstrate sufficient caprock and low migration risk, be at suitable depth for dense-phase CO₂ (unless otherwise justified), and align with PCS geological guidance.
3.5 Conditions for CO₂ Transport Systems
Transport systems (pipelines, ships, trucks, rail) must be engineered for CO₂ at appropriate pressure/temperature for dense-phase or supercritical transport. CO₂ must be traceable through mass balance and energy inputs, compression operations, and leakage points must be monitorable or reasonably estimated. Mixed transport systems are eligible with documented transitions and monitoring continuity.
3.6 Conditions for Injection Operations
Injection wells must satisfy PCS engineering standards for integrity, safety, and environmental protection. Projects must demonstrate injection pressures below formation fracture gradients, continuous injection volume monitoring, and protective measures to prevent wellbore leakage. Injection operations must be part of an integrated site development and management plan.
3.7 Conditions for Demonstrating Permanent Storage
Projects must demonstrate long-term containment potential via site characterization, reservoir modeling, and monitoring plans that describe trapping mechanisms, plume migration, and stabilization. Long-term monitoring and liabilities must be defined. Projects lacking demonstrable long-term containment due to geological uncertainty are not applicable.
3.8 Conditions for Enhanced Hydrocarbon Recovery
EOR/EGR projects are eligible only when net geological storage of CO₂ can be demonstrated (injected CO₂ exceeds CO₂ produced/vented). Projects must ensure injected CO₂ will remain within the storage complex and not migrate to shallower formations.
3.9 Regulatory and Host Country Preconditions
Projects must operate where geological storage is permitted and legal frameworks exist for injection, monitoring, and stewardship. Projects must comply with applicable permits. Where host country regulations are incomplete, projects must demonstrate compliance with PCS requirements as the minimum standard.
3.10 Exclusions from Applicability
Excluded: CO₂ utilization without permanent geological storage, mineralization outside geological formations, ocean storage, biological storage, short-term carbon management, and claims for avoided emissions without physical containment.
3.11 Importance of Applicability Conditions in Safeguarding Integrity
Applicability conditions ensure only technically robust, environmentally sound, and permanently beneficial CCS activities are credited under PCS, protecting against over-crediting and misapplication.
Chapter 4 - Project Boundary
4.1 Purpose of the Project Boundary
The project boundary establishes the physical, operational, and temporal limits for identifying, quantifying, and monitoring greenhouse gas emissions and removals. A well-defined boundary ensures inclusion of all relevant emissions sources and sinks associated with capture, transport, and permanent geological storage.
4.2 Physical and Operational Boundary for CCS Projects
The boundary encompasses facilities, infrastructure, and systems involved in capture, conditioning, compression, transport to injection site, injection, and storage. Include upstream and downstream processes that materially influence project emissions. Even when only certain modules are applied, the CCS chain must be described to the extent necessary for leakage pathway monitoring and environmental integrity.
4.3 Geographical Boundary
Covers all regions where project activities occur: capture facility surroundings, full transport route, subsurface and surface areas associated with the storage complex. If project spans multiple jurisdictions, reflect all applicable regulatory requirements and monitoring responsibilities. For storage, encompass plume migration area, pressure footprint, and potential leakage pathways.
4.4 Temporal Boundary
Begins when CO₂ first enters the capture system and continues through transport, injection, and permanent storage, including the crediting period and post-injection monitoring period. Includes operational phase, temporary cessations, plume stabilization, and required monitoring to confirm absence of leakage.
4.5 Inclusion of Emission Sources within the Boundary
Include all anthropogenic emissions associated with capture, conditioning, compression, transport, injection, storage, and monitoring: energy consumption, fugitive emissions, pipeline or ship transport emissions, injection operations, and potential leakage from storage, wellbores, faults, or geological structures. Immaterial sources may be excluded only if justified.
4.6 Storage Complex and Subsurface Boundary
Define the storage complex (target reservoir, caprock, confining layers, secondary trapping systems). Encompass expected plume extent and pressure field. Account for possible leakage through wells, faults, fractures, or permeable pathways. Align the storage complex definition with ISO 27914 and validate with geological characterization, reservoir modeling, and risk assessment.
4.7 Surface and Near-Surface Boundary
Include surface facilities associated with injection and areas where surface or near-surface leakage could occur. Monitoring equipment, soil gas zones, groundwater wells, and corrective infrastructure must be included.
4.8 Boundary Across Methodology Modules
Boundary must reflect modules applied. Core requires a holistic description to ensure coherence across the CCS chain and avoid fragmentation or omission of emissions, monitoring, or leakage responsibilities.
4.9 Justification of Boundary Completeness
Project developers must justify boundary completeness with engineering diagrams, process flow descriptions, geological maps, reservoir simulations, and monitoring plans. Exclusions or assumptions must be explained and supported by evidence demonstrating negligible effect on emission calculations.
4.10 Importance of a Complete and Accurate Project Boundary
A comprehensive project boundary underpins environmental integrity, accurate quantification, effective monitoring, and long-term stewardship of stored CO₂.
Chapter 5 - Baseline Scenario Determination
5.1 Purpose of Baseline Scenario Determination
The baseline represents the counterfactual where the CCS project is not implemented; it ensures claimed reductions are real and additional. For CCS, the baseline must credibly reflect emissions that would have occurred absent capture, transport, and storage.
5.2 General Principles of Baseline Setting
Baselines must be conservative, transparent, realistic, and grounded in verifiable evidence. They should align with IPCC guidance and not assume speculative facility improvements unless mandated.
5.3 Baseline Scenario for CO₂ Emitting Facilities (Without Capture)
Baseline assumes continued operation emitting CO₂ via normal pathways. Baseline CO₂ equals the volume that would have been emitted during the crediting period without the project, using historical data, production levels, and conservative smoothing of temporary fluctuations.
5.4 Role of Regulations and Policies in Baseline Determination
Binding regulations that mandate capture or emission reductions must be reflected in the baseline. Adopted but unenforced regulations should be conservatively considered if compliance is reasonably expected. Voluntary commitments do not automatically alter the baseline.
5.5 Baseline for CO₂ Capture Module (Module A)
For Module A, baseline quantity of CO₂ captured is zero; in absence of CCS, CO₂ would have been emitted. Baseline must not assume partial capture unless already occurring or mandated.
5.6 Baseline for CO₂ Transport Activities (Module B)
For Module B, baseline transport emissions are zero because transport would not operate without captured CO₂.
5.7 Baseline for Geological Storage (Module C)
For Module C, the baseline assumes zero injected or stored CO₂; injection-related emissions are zero in the baseline.
5.8 Future Production and Operational Changes
Consider future changes only when supported by documented expansion plans, regulatory expectations, or committed investments. Avoid inflating baselines through speculative production increases.
5.9 Treatment of Uncertain or Variable Conditions
Use conservative values when uncertainty is significant. Sensitivity analyses can inform adjustments, and all assumptions must be justified with evidence.
5.10 Avoiding Overestimation of Baseline Emissions
Exclude abnormal conditions (emergency flaring, temporary equipment failures) unless they represent normal operations. Baselines should err on conservative side to avoid over-crediting.
5.11 Baseline in Multi-Source or Multi-Facility Settings
Establish baselines per source and aggregate for calculations. Each source must meet applicability and additionality unless integrated operations justify combined baseline determination.
5.12 Baseline Transparency and Documentation Requirements
Document all assumptions, calculations, datasets, and projections; support historical data with metered values and production records. Retain baseline documentation through crediting and post-injection monitoring periods.
5.13 Importance of Conservative Baseline Determination
Conservativeness ensures PCUs reflect real climate benefits and aligns the methodology with international integrity frameworks.
Chapter 6 - Additionality Demonstration
6.1 Purpose of Additionality Requirements
Additionality ensures CCS projects generate emission reductions that would not have occurred absent the project. Given CCS capital intensity and long-term liability, robust additionality assessment is critical.
6.2 Framework for Demonstrating Additionality
PCS applies a structured framework examining regulatory, financial, technological, and implementation conditions at the decision point. Demonstration must be based on transparent, verifiable evidence.
6.3 Regulatory Surplus Test
A project is additional only if not required by law or binding regulation. If regulation mandates CCS, project fails additionality. Where mandates are pending enforcement, additionality may hold only if the project begins before compliance becomes mandatory and evidence is provided.
Table 6.1 — Regulatory Additionality Assessment
CCS is legally mandated for this facility
Regulation in force
Not additional
CCS is mandated but implementation date not enforced
Regulation adopted, pending enforcement
Additional only if project begins before compliance becomes mandatory, and evidence is provided
CCS is encouraged but not mandated (policies, incentives)
Informational or voluntary policy instruments
Additional
No CCS-related regulations exist
No legal constraints
Additional
6.4 Financial Additionality Test
A CCS project is financially additional when not economically viable without carbon credit revenue. Developers must demonstrate unfavorable IRR/NPV/payback without carbon revenue, high CAPEX/OPEX, and lack of sufficient market incentives. Financial models must be transparent.
Table 6.2 — Financial Additionality Evidence Framework
CAPEX
Capture, transport, storage costs exceed commercial returns
Feasibility studies, engineering cost reports
OPEX
Operating costs require carbon revenue to break even
Operational budgets, compressor energy cost analysis
IRR/NPV
Negative or insufficient IRR without PCUs
Financial model outputs, auditor assurance
Alternative investments
Business-as-usual investments offer better returns
Corporate investment criteria
6.5 Technological Additionality
Projects must show CCS is not standard practice in the sector/region and that technologies used are not commonplace at the facility type. This is important for first-of-a-kind deployments or novel storage formations.
6.6 Implementation Barrier Test
Projects must demonstrate significant barriers (high upfront costs, long appraisal lead times, lack of transport infrastructure, regulatory uncertainty, high energy/OPEX, stakeholder challenges) that carbon finance helps overcome.
6.7 Common Practice Analysis
Assess CCS prevalence in the region/sector (projects in operation, adoption rates, technological maturity). If CCS is common practice, project may not be additional.
6.8 Additionality Demonstration Summary
Consolidate regulatory, financial, technological, and common-practice assessments. Validation must trace decision timeline, constraints without CCS, financial implications, and supporting documents. The PDD must include narrative, evidence summary, and annexed supporting documents.
Table 6.3 — Additionality Summary Table (for PDD)
Regulatory surplus
Pass/Fail
Regulatory documentation
VVB confirms
Financial viability
Pass/Fail
Financial model, cost statements
VVB confirms
Technological additionality
Pass/Fail
Industry benchmarks
VVB confirms
Common practice test
Pass/Fail
Sectoral analysis
VVB confirms
6.9 Importance of Additionality in CCS Projects
Additionality is critical due to significant infrastructure investment and long-term responsibility. Strong additionality rules prevent over-crediting and ensure PCUs reward genuine mitigation beyond business as usual.
Chapter 7 - Quantification Of Emission Reductions
7.1 Purpose of Quantification Framework
Defines how net emission reductions attributable to CCS projects are calculated, capturing all emissions associated with capture, transport, injection, storage, and leakage. Apply module-specific equations and report monitored parameters transparently.
7.2 General Structure of Quantification
Emission reductions for CCS projects are calculated as the difference between baseline emissions, which represent the CO₂ that would have been emitted to the atmosphere in the absence of the project, and project emissions, which represent emissions associated with operating the CCS chain plus any leakage from geological storage or infrastructure. The basic structure is as follows:
ER_net=BE-PE-LE
Where:
BE = baseline emissions (CO₂ that would have been released without the project)
PE = project emissions from capture, transport, compression, storage operations
LE = leakage emissions (capture, transport, wellbores, reservoir)
7.3 Baseline Emissions (BE)
Baseline emissions correspond to the quantity of CO₂ actually captured and stored under the project (adjusted for purity and moisture), since in absence of CCS that CO₂ would have been emitted.
BE=CO2_(emitted,baseline)
In practical terms, the baseline emissions correspond exactly to the quantity of CO₂ actually captured and stored under the project. Thus, baseline emissions are equal to the mass of CO₂ stored in Module C (after adjusting for CO₂ purity and moisture content), provided that the facility would otherwise emit this CO₂ without restrictions.
No baseline emissions are associated with transport or injection because, without the project, these systems would not operate.
Table 7.1 — Baseline Component Overview
Component
Baseline Value
Rationale
CO₂ emitted from facility
Quantity equal to CO₂ captured and injected
In absence of CCS, all captured CO₂ would be vented
Transport systems
Zero
Would not exist without CCS
Injection and storage
Zero
No storage occurs without CCS
7.4 Project Emissions (PE)
Project emissions include energy-related emissions, fugitive emissions, venting, recompression, monitoring and injection operations, and indirect emissions from electricity, heat, or auxiliary fuel use.
Categories include:
Emissions from energy used for CO₂ capture
Emissions from compression and conditioning
Emissions from transport infrastructure
Emissions from booster stations or recompression
Emissions from injection operations
Fugitive emissions from equipment
Venting during maintenance or upset conditions
Emissions associated with storage monitoring and reservoir management
Indirect emissions from electricity, heat, or auxiliary fuel use
Each category is quantified per module.
Project Emissions Equation (General Form)
PE=PE_cap+PE_trans+PE_inj+PE_stor
Where:
PEcap = emissions from CO₂ capture (Module A)
PEtrans = emissions from CO₂ transport (Module B)
PEinj = emissions from injection systems (Module C)
PEstor = operational emissions associated with geological storage (Module C)
Each term is derived according to its module and reported annually.
7.5 Leakage Emissions (LE)
Leakage emissions represent unintended releases of CO₂ from any part of the CCS chain. Leakage may occur:
At the capture facility (e.g., venting of CO₂-rich gas)
During transport (pipeline or ship leaks)
At wellheads, injection wells, or monitoring wells
Through faults, fractures, or other geological pathways
Into shallow groundwater or to the surface
Leakage must be quantified conservatively. If leakage cannot be measured directly, modeling or upper-bound estimates must be used.
Leakage Equation (General Form)
LE=LE_cap+LE_trans+LE_well+LE_geo
Where:
LE_cap = leakage during capture
LE_trans = leakage during transport
LE_well = leakage through wells
LE_geo = geological leakage from storage complex
105. Leakage is deducted one-to-one from credited reductions.
106. If leakage exceeds certain thresholds or becomes continuous, PCS requires suspension of issuance and activation of corrective measures.
7.6 Net Stored CO₂
CO2_(stored,net)=CO2_inj-LE_geo
Support with mass balance measurements, flow meters, pressure/temperature records, and reservoir simulation.
7.7 Consolidated Emission Reduction Formula
ER_net=CO2_baseline-(PE_cap+PE_trans+PE_inj+PE_stor)-(LE_cap+LE_trans+LE_well+LE_geo)
This is the master quantification equation for the PCS CCS methodology.
To maintain environmental integrity:
All terms must be monitored using calibrated instrumentation.
All indirect emissions must be quantified using emission factors consistent with PCS and IPCC guidance.
Leakage must be treated with high conservativeness.
Storage permanence must be demonstrated through geological modeling and monitoring.
7.8 Mass Balance Requirements Across Modules
Maintain mass balance across capture, transport, and injection meters; investigate discrepancies above uncertainty thresholds. Calibrate meters and reconcile mass flows annually. Unexplained shortfall treated as leakage.
CO2_captured≥CO2_transported≥CO2_delivered≥CO2_inj
Any discrepancies above acceptable uncertainty thresholds must be investigated and clarified.
7.9 Quantification of Greenhouse Gases Other than CO₂
Although CCS projects are primarily focused on CO₂, there may be emissions of CH₄ or N₂O from energy systems, equipment leaks, or operational anomalies. These must be included using IPCC 100-year Global Warming Potentials (GWP100). All non-CO₂ emissions must be clearly documented.
7.10 Uncertainty and Conservativeness Requirements
When uncertainty is significant, apply conservative emission factors, upper-bound leakage estimates, downward adjustments to stored CO₂, or exclude questionable data. Evaluate and report uncertainty in the monitoring plan.
7.11 Quantification Summary Table (Required in PDD)
Table 7.2 — Summary of Quantified Components
Baseline emissions
CO₂ that would have been emitted
Core
All
Capture emissions
Energy and fugitive emissions
Module A
Capture projects
Transport emissions
Compression, recompression, leaks
Module B
Transport projects
Injection emissions
Pumping, wellhead operations
Module C
Injection projects
Storage emissions
Monitoring-related energy
Module C
Storage projects
Leakage
Any unintended CO₂ release
All
Mandatory
7.12 Importance of Comprehensive Quantification
Comprehensive and conservative accounting ensures PCUs represent genuine, durable climate benefits.
Chapter 8 - Monitoring Requirements
8.1 Purpose of Monitoring Requirements
Monitoring ensures accurate measurement of parameters needed for quantification and verification of long-term containment across capture, transport, injection, storage, and leakage pathways.
8.2 General Monitoring Principles
Prefer direct measurements; use indirect estimates only when measurement is infeasible. Calibrate and maintain instruments per standards. Ensure transparency, replicability, and detection of anomalies. Archive monitoring data for the crediting and post-injection monitoring periods.
8.3 Monitoring System Boundaries
Cover capture unit, compression/dehydration systems, transport infrastructure, injection systems, storage complex, monitoring wells, surface monitoring, and auxiliary equipment. Design to identify discrepancies in captured, transported, and injected CO₂ quantities and detect leakage.
8.4 Monitoring Requirements for Capture Operations (Module A)
Monitor mass of CO₂ captured, purity, pressure, temperature, moisture content, flow rate, and energy consumption (electricity, heat, steam). Monitor fugitive emissions via periodic surveys or continuous systems. Record operational anomalies.
8.5 Monitoring Requirements for Transport Operations (Module B)
Monitor CO₂ entering and exiting transport system, flow, pressure, temperature, energy consumption for compression/pumping/shipping, and transport integrity (inspections, pressure anomalies). For ships, monitor tank capacity, loading/unloading records, and boil-off.
8.6 Monitoring Requirements for Injection Operations (Module C)
Monitor CO₂ flow rate, density, cumulative injected mass, injection pressure, wellhead temperature, annulus pressure. Log downhole pressure/temperature where available. Document operational events and pressure behavior.
8.7 Monitoring Requirements for Geological Storage (Module C)
Verify containment via reservoir pressure/temperature monitoring, plume mapping (seismic/geophysical), groundwater and environmental monitoring, near-surface monitoring (where risk justifies), micro-seismic monitoring, and well integrity checks.
8.8 Monitoring Requirements for Leakage Detection
Implement risk-based leakage detection informed by geological characterization, structural mapping, faults/fracture assessments, historical well records, and reservoir/seal integrity studies. Investigate indications promptly.
Table 8.1 — Leakage Monitoring Components
Well integrity monitoring
Pressure testing, annulus monitoring, cement bond logs
Detect wellbore leakage
Reservoir surveillance
Seismic surveys, CO₂ plume mapping
Confirm containment
Groundwater monitoring
Geochemical sampling, tracer analysis
Detect subsurface migration
Surface monitoring
Soil CO₂ flux, atmospheric sensors
Identify surface leakage
Pipeline monitoring
Pressure drop detection, corrosion inspection
Detect transport leakage
8.9 Monitoring of Energy Use and Indirect Emissions
Monitor electricity, natural gas, steam, and auxiliary fuels for capture, transport, injection, and monitoring systems. Apply emission factors consistent with national inventory or PCS-approved factors.
8.10 Instrument Calibration and Data Quality Assurance
Calibrate monitoring equipment per manufacturer and industry standards. Maintain calibration records, QA/QC procedures, and report data gaps/anomalies with conservative substituted values where necessary.
8.11 Treatment of Abnormal Operating Conditions
Document and conservatively treat unplanned venting, equipment failures, injection interruptions, or pressure excursions.
8.12 Monitoring Frequency and Minimum Requirements
Match monitoring frequency to parameter sensitivity and risk. Capture, transport, and injection flow measurements must be continuous. Groundwater sampling, geophysical surveys, and reservoir model updates at site-specific intervals.
Table 8.2 — Minimum Monitoring Frequencies (Illustrative)
CO₂ captured
Continuous
CO₂ transported
Continuous
CO₂ injected
Continuous
Injection pressure
Continuous
Groundwater chemistry
Semi-annual or risk-based
Seismic plume tracking
Annual or biennial
Well integrity testing
Annual
Surface CO₂ flux monitoring
Annual or risk-based
8.13 Data Archiving and Traceability
Store monitoring data securely, time-stamped, instrument-linked; make available for validation, verification, and audits. Retain records for the crediting and post-injection monitoring periods.
8.14 Importance of Monitoring within CCS MRV
High-quality MRV systems ensure safe containment, credible PCUs, detection of anomalies, and support corrective actions to protect people, ecosystems, and groundwater.
Chapter 9 - Data And Parameters
9.1 Purpose of Data and Parameter Requirements
Define monitored and default parameters for calculating emission reductions. Include parameters in PDD and PMR with measurement methods, uncertainty ranges, and data sources.
9.2 General Principles for Parameter Selection and Use
Use reliable, verifiable data; prioritise direct measurements; default values from PCS-approved sources (IPCC, national factors); calibrate instruments and document changes.
9.3 Categories of Parameters
Monitored parameters (continuous)
Monitored parameters (periodic)
Calculated parameters
Default parameters
Justify category use in the monitoring plan.
9.4 Key Monitored Parameters (Continuous Measurement)
Table 9.1 — Continuously Monitored Parameters
CO₂ captured
t CO₂
Mass flow entering compression
CO₂ transported
t CO₂
Mass flow at transport entry/exit
CO₂ injected
t CO₂
Mass injected into reservoir
CO₂ purity
%
Mole fraction
Moisture content
% or ppm
Affects density and mass
Injection pressure
MPa
Wellhead/downhole pressure
Injection temperature
°C
Temperature at injection
Flow rate
kg/s or t/h
Flow at process stages
9.5 Energy-Related Parameters
Table 9.2 — Energy Monitoring Parameters
Electricity for capture
MWh
Capture energy consumption
Electricity for compression
MWh
CO₂ compression energy
Electricity for transport
MWh
Pipeline pumping or ship loading
Fuel for transport
GJ or liters
Ship/truck/rail fuel
Energy for injection
MWh
Injection pump energy
Apply emission factors from Section 9.9.
9.6 Monitoring Parameters for Geological Storage
Table 9.3 — Storage Monitoring Parameters
Reservoir pressure
MPa
Plume migration and storage performance
Plume extent
km² or qualitative
Mapped by geophysical surveys
Groundwater chemistry
mg/L
pH, alkalinity, dissolved ions
Micro-seismic activity
events/time
Geomechanical changes
Well integrity indicators
various
Cement bond logs, annulus pressure
9.7 Leakage Parameters
Table 9.4 — Leakage Parameters
Capture facility leakage
t CO₂
Fugitive emissions or bypass events
Transport leakage
t CO₂
Losses from pipeline/ship/tanks
Wellbore leakage
t CO₂
Leaks from injection or abandoned wells
Geological leakage
t CO₂
CO₂ released into non-target formations or surface
Use conservative estimates when uncertainty exists.
9.8 Calculated Parameters
Table 9.5 — Calculated Parameters
Net stored CO₂
Injected CO₂ minus geological leakage
Project emissions
Sum of all emissions from CCS operations
Baseline emissions
CO₂ that would have been emitted without CCS
Net emission reductions
BE − PE − LE
9.9 Default Parameters and Constants
Table 9.6 — Default Emission Factors
Electricity emission factor
Host country or PCS default
t CO₂e/MWh
Country-specific priority
Diesel fuel emission factor
IPCC 2006
kg CO₂/L
Standardized value
Natural gas factor
IPCC 2006
kg CO₂/GJ
May vary by methane content
GWP (CO₂)
IPCC AR6
1
Default
GWP (CH₄)
IPCC AR6
27.2
100-year horizon
GWP (N₂O)
IPCC AR6
273
100-year horizon
Host country inventory factors may be adopted subject to PCS approval.
9.10 Data Sources, Quality Requirements, and Validation
Document data provenance, calibration certificates, QA/QC procedures, treatment of gaps, and uncertainty analysis. VVBs evaluate data reliability.
9.11 Data Storage and Recordkeeping
Archive raw and processed monitoring data, model outputs, seismic data, well logs, energy records, lab reports, and monitoring plans. Retain for crediting period plus post-injection monitoring period.
9.12 Parameter Summary Table for PDD
Table 9.7 — Summary of Required Parameters for Inclusion in PDD
CO₂ mass flows
Yes
A, B, C
Meter specs, calibration
Energy use
Yes
A, B, C
Utility bills, logs
Storage parameters
Yes
C
Geological monitoring data
Leakage
Mandatory
All
Monitoring reports
Default factors
As needed
All
Referenced sources
Uncertainty
Yes
All
Statistical justification
9.13 Importance of Parameter Transparency
Transparent parameter documentation supports VVB assessments, PCS governance alignment, Article 6 reporting, and market confidence.
Chapter 10 - Leakage, Corrective Measures, And Liability
10.1 Purpose of Leakage and Corrective Measure Provisions
Defines obligations to identify, quantify, and address leakage events; maintain responsibility for containment during crediting and post-injection monitoring; and clarify liability under PCS governance.
10.2 Definition of Leakage Under PCS
Leakage = any measurable CO₂ release from the CCS chain outside intended project boundary or storage complex (capture/compression, transport systems, wellbores, faults/fractures, groundwater/surface water/atmosphere).
10.3 Leakage Pathways
Evaluate engineered and geological pathways during site characterization and continuously during monitoring.
Table 10.1 — Leakage Pathway Categories
Surface facility leakage
Venting or fugitive emissions at capture/compression units
Pipeline or transport leakage
Loss from pipelines, ships, transfer stations
Well integrity leakage
Migration through injection, monitoring, or abandoned wells
Geological leakage
Movement across sealing formations, faults, caprock failures
Groundwater leakage
CO₂ intrusion into potable/protected groundwater
10.4 Leakage Quantification Requirements
Quantify leakage via direct measurement when possible; otherwise use indirect estimation supported by engineering/geological evidence. When not measurable, apply upper-bound estimates. Deduct leakage one-for-one from emission reductions.
10.5 Leakage Thresholds and Triggers for Corrective Action
Triggers include anomalous pressure behavior, geophysical anomalies, elevated CO₂ in soil/groundwater, unexplained mass-balance losses, or surface CO₂ detection. Initiate corrective measures immediately after confirmation.
10.6 Corrective Measures Requirements
Corrective measures plan (required in PDD) must include identification of cause/pathway, immediate stabilizing actions, engineering interventions (re-cementing, plugging), reservoir management (altering injection rates), intensified monitoring, restoration actions, and reporting to PCS/VVB.
10.7 Suspension of Credit Issuance During Leakage
Suspend claiming reductions for affected periods; PCS may halt issuance until leakage is resolved. Back-crediting allowed only after confirmed remediation and accounting.
10.8 Leakage During Capture and Transport
Quantify via operational records, gas detection surveys, or mass balance discrepancy. Add to PE and deduct from reductions. Persistent leakage triggers VVB scrutiny.
10.9 Leakage Through Injection or Monitoring Wells
Assess mechanical integrity of all wells; monitor annulus pressure and perform integrity testing. Remediate detected well leakage promptly.
10.10 Geological Leakage and Reservoir Integrity
If CO₂ migrates outside approved complex, notify PCS, activate corrective measures, intensify monitoring, update simulations, and potentially restrict injection until behavior is understood.
10.11 Long-Term Containment Requirements
Demonstrate CO₂ will remain permanently stored via characterization and long-term simulations. Post-injection monitoring must confirm stabilization, supported by VVB verification.
10.12 Liability for Leakage
Project Developer retains liability during injection and crediting period and through post-injection monitoring until PCS transfers or closes liability. Liability includes corrective measures, remediation, compensation, and replacement of invalidated PCUs. PCS may revoke issued PCUs if prior reductions were overstated.
10.13 Documentation and Reporting Requirements
Document detection/confirmation, diagnostics, corrective measures, monitoring results, impacts, and regulatory communications. Include leakage documentation in PMR and VVB verification.
10.14 Importance of Leakage Management in CCS Integrity
Robust leakage and liability requirements protect environmental integrity and ensure PCUs reflect durable climate benefits.
Chapter 11 - Permanence, Post-Injection Monitoring, and Liability Transition
11.1 Concept of Geological Permanence
Permanence relies on trapping mechanisms (structural, residual, solubility, mineralization) and requires site characterization, predictive modeling, monitoring, and verification.
11.2 Post-Injection Monitoring Period
Begins when injection permanently ceases and continues until stable pressure, plume immobilization, and absence of leakage risk are demonstrated. Duration is site-specific and may extend beyond methodology minimums if reservoir behavior warrants.
11.3 Criteria for Demonstrating Plume Stabilization
Demonstrate reduced migration rates, diminishing pressure gradients, and immobilization via updated reservoir simulations, seismic interpretation, pressure history, and geochemical indicators. VVB verification is required.
11.4 Criteria for Demonstrating Pressure Stabilization
Show declining pressures in line with models, stabilization below fracture gradients and thresholds, and absence of anomalies suggesting movement beyond storage boundaries.
11.5 Long-Term Monitoring Requirements
Continue monitoring at levels sufficient to detect significant deviations: periodic seismic/geophysical imaging, groundwater chemistry monitoring, reservoir pressure and temperature trends, well integrity assessments, and near-surface monitoring where justified. Frequencies may be reduced as confidence increases.
Table 11.1 — Long-Term Monitoring Components
Reservoir pressure
Confirm depressurization & containment
Annual → biennial
Plume imaging
Confirm immobilization
3–5 year intervals
Groundwater sampling
Detect subsurface migration
Annual → risk-based
Well integrity
Ensure no leakage pathways
Annual
Surface monitoring
Detect atmospheric or soil CO₂
Risk-based
11.6 Conditions for Demonstrating Absence of Leakage Risk
Requires updated risk assessment confirming negligible leakage probability; no anomalies in monitoring records; reservoir behavior consistent with models; and absence of leakage evidence throughout post-injection period.
11.7 Criteria for Transfer or Termination of Liability
PCS may transfer/terminate liability only when injection has ceased permanently, plume and pressure stabilization demonstrated, no leakage occurred (or fully remediated), long-term monitoring indicates containment, models confirm long-term security, and relevant authorities agree.
11.8 Conditions for Continuing or Extended Monitoring
Extend monitoring if plume migration exceeds models, unexpected pressure/geochemical behavior emerges, leakage indications require further investigation, or data are insufficient to demonstrate security.
11.9 Relationship Between Permanence and PCU Issuance
PCUs represent permanent removals only when long-term containment is ensured. If leakage occurs after issuance, PCS may require replacement, apply sanctions, or invalidate credits.
11.10 Documentation and Reporting Requirements
Prepare Long-Term Monitoring Report with updated models, seismic/geophysical interpretations, monitoring summaries, well integrity assessments, and evidence against liability-transfer criteria. VVB verification required.
11.11 Importance of Permanence in CCS Methodologies
Permanence underpins the durability of geological storage; stringent permanence criteria align PCS with global expectations and Article 6 transparency.
Module A - CO₂ Capture
Chapter A1 - Introduction And Scope
A1.1 Purpose of the Capture Module
Provides requirements to quantify emissions associated with capture, including mass captured, energy-related emissions, leakage/venting losses before transport, and ensures alignment with international best practices.
A1.2 Role of Capture in the CCS Value Chain
Capture separates and conditions CO₂ for transport/storage; includes chemical absorption, solvents, membranes, adsorption, oxyfuel, cryogenic separation. Capture performance determines CO₂ availability for storage and influences project emissions.
A1.3 Scope of This Module
Applies to separation, purification, dehydration, and compression of CO₂ prior to transport (flue gas treatment, pre/post-combustion, industrial process capture, oxyfuel, solvent regeneration, CO₂ conditioning and compression). Activities beyond final compression outlet fall under Module B.
A1.4 Relationship With Core Methodology
Module A supplements the Core methodology, providing detailed requirements for captured CO₂ mass, capture energy emissions, fugitive/venting emissions, capture efficiency, and mass balance reconciliation. Module A must be paired with at least Module C for PCU issuance.
Chapter A2 - Applicability Of The Capture Module
A2.1 Eligible Capture Technologies
Includes chemical absorption, physical solvents, membranes, PSA/TSA, oxyfuel, cryogenic separation, and hybrid systems. Technology-neutral if CO₂ stream is anthropogenic, mass flow monitorable, and purity measurable.
A2.2 Ineligible Capture Activities
Excludes Direct Air Capture, biological capture, CO₂ capture solely for utilization without geological storage, temporary capture without permanent storage, and EOR without net storage demonstration.
A2.3 CO₂ Stream Requirements
CO₂ purity must be ≥ 90% unless justified; measure water content and non-condensable gases; update compositional data with process changes.
A2.4 Applicability to Multi-Source Capture Projects
Monitor each source separately, report capture efficiency per source, and reconcile mass balance across all inflows/outflows.
Chapter A3 - Project Boundary For Capture Operations
A3.1 Physical and Operational Boundary
Includes flue gas intake, pre-treatment, absorber, solvent regeneration, dehydration, compression up to outlet flange feeding transport, fugitive emission points, vent stacks, and solvent/sorbent storage/makeup systems.
A3.2 Temporal Boundary
Continuous monitoring during capture operation; record unplanned downtime and abnormal conditions.
A3.3 Exclusions
Exclude emissions not directly attributable to the capture system.
Chapter A4 - Quantification Of Capture Emissions
This section provides the fundamental equations for calculating project emissions from capture.
A4.1 Mass of CO₂ Captured
The mass of CO₂ captured per monitoring period is calculated from continuous metering:
CO2_cap=∫FR_CO2⋅dt⋅Density_CO2
Where:
FR_CO2= CO₂ flow rate
Density_CO2= density corrected for temperature, pressure, and purity
Purity adjustments:
CO2_(cap,adj)=CO2_cap×Purity_CO2
Moisture adjustments:
CO2_dry=CO2_(cap,adj)×(1-H2O_cont)
A4.2 Capture Efficiency
Capture efficiency (η) must be calculated and reported:
η_cap=(CO2_dry)/(CO2_inlet )
Where CO2_inlet is measured or calculated via flue gas analysis.
A4.3 Emissions From Capture Energy Use
Energy-related emissions:
PE_(cap,energy)=E_cap×EF_elec+Fuel_cap×EF_fuel
A4.4 Fugitive Emissions and Venting
PE_(cap,fugitive)=∑LE_cap
Venting during maintenance or regeneration must be measured or conservatively estimated.
A4.5 Total Capture Emissions
PE_cap=PE_(cap,energy)+PE_(cap,fugitive)
Chapter A5 - Monitoring Requirements For Capture
A5.1 Required Monitoring Components
Continuous CO₂ flow meters
Purity analysis (GC or equivalent)
Moisture analysis
Flue gas inlet CO₂ monitoring
Energy meters (electricity, heat, fuel)
Fugitive emission surveys
Vent logs and maintenance events
A5.2 Instrument Calibration Requirements
Calibrate to ISO or national standards; maintain calibration records; calibrate annually or per manufacturer guidance.
A5.3 Data Logging and Redundancy
Continuous data collection, backup storage, redundant metering at key points, and error-detection algorithms.
Chapter A6 - Data And Parameters For Capture
Table A6.1 — Capture Parameters
CO₂ flow rate (FR_CO2)
kg/s
Continuous measurement
CO₂ purity (Purity_CO2)
%
Mole fraction
Moisture (H2O_cont)
% or ppm
Affects mass
Energy use (E_cap)
MWh
Capture energy
Fuel use (Fuel_cap)
GJ or liters
Auxiliary energy
Fugitive emissions (LE_cap)
t CO₂
Measured or estimated
Chapter A7 - Additional Provisions
A7.1 Solvent or Sorbent Degradation
Quantify effects of degradation on emissions and energy (e.g., additional steam use).
A7.2 Abnormal Operating Conditions
Log unplanned shutdowns, venting, and malfunctions; treat data conservatively.
A7.3 Waste Streams
Manage chemical waste and spent solvent per environmental regulations.
Module B - CO₂ Transport
Chapter B1 - Introduction And Scope
B1.1 Purpose of the Transport Module
Defines requirements for quantifying emissions and monitoring during CO₂ transport from capture compression outlet to injection system inlet. Ensures transport-related emissions are included and mass flows reconciled.
B1.2 Scope of This Module
Applies to pipeline, ship, rail, or truck transport, intermediate storage, recompression stations, and handling operations. Technology-neutral and accommodates multi-modal transport.
B1.3 Relationship With Other Modules
Bridges Module A (Capture) and Module C (Storage). Metering systems must provide consistent and reconcilable measurements.
Chapter B2 - Applicability Of The Transport Module
B2.1 Eligible Transport Options
Pipelines (onshore/offshore), ships (with liquefaction/storage), trucks/rail for small volumes, and shared infrastructure where attribution is feasible.
B2.2 Applicability to Multi-Modal Transport
Describe each segment and ensure mass balance across transfers with compliant measurements.
B2.3 Excluded Transport Activities
Exclude transport upstream of capture (internal ducting) and transport to utilization without geological storage.
Chapter B3 - Project Boundary For Transport
B3.1 Physical and Operational Boundary
The transport boundary begins at the outlet flange of the final compression stage at the capture facility and ends at the inlet flange of the injection system at the storage site. The boundary encompasses all pipelines, manifolds, valves, compressors, booster stations, intermediate tanks, ship loading facilities, unloading terminals, and any monitoring systems used to verify CO₂ mass flow and detect leakage. For ship transport, the boundary includes liquefaction units, shipboard storage tanks, and port transfer operations. The boundary must also encompass potential leakage pathways such as pipeline corrosion points, thermal stress zones, weld joints, and pressure-sensitive components.
B3.2 Temporal Boundary
Monitoring and quantification apply continuously during periods when CO₂ is transported. For ship-based systems, the boundary includes loading, voyage, and unloading stages. Interruptions, transfers, and downtime must be recorded, and any CO₂ vented or lost during such periods must be quantified.
B3.3 Justification of Boundary Completeness
The Project Developer must justify the completeness of the boundary by describing all relevant transport infrastructure using engineering diagrams, equipment specifications, operating manuals, and risk assessments. The Validation and Verification Body evaluates the adequacy of this justification.
Chapter B4 - Quantification Of Transport Emissions And CO₂ Delivery
B4.1 CO₂ Delivered to the Injection System
The central quantification requirement of Module B is determining the mass of CO₂ delivered to the storage site. This is calculated through continuous monitoring of CO₂ flow, pressure, and temperature at the inlet of the injection system. The formula parallels Module A:
CO2_delivered=∫FR_(CO2,delivery)⋅dt⋅Density_(CO2,delivery)
This value represents the CO₂ available for injection and must align with mass balance calculations across modules.
B4.2 Emissions From Compression and Recompression
Transport systems often require initial and intermediate compression to maintain dense-phase conditions. Emissions associated with electricity or fuel used for compression must be calculated as:
PE_comp=E_comp×EF_elec+Fuel_comp×EF_fuel
B4.3 Emissions From Pumping, Shipping, or Transfer Operations
Pipeline pumping emissions are proportional to distance, elevation changes, and frictional losses. Ship transport emissions are proportional to voyage distance, engine fuel consumption, and auxiliary power loads. These emissions must be quantified using monitored energy use.
B4.4 Leakage During Transport
Leakage is quantified as:
LE_trans=CO2_entry-CO2_exit
Where:
CO2_entry is the mass entering the transport system
CO2_exit is the mass reaching the storage site
Any discrepancy outside expected measurement uncertainty is treated as leakage unless justified otherwise.
B4.5 Total Transport Emissions
PE_trans=PE_comp+PE_pump+PE_ship+PE_handling+LE_trans
All emissions deducted from net reductions appear transparently in the PMR.
Chapter B5 - Monitoring Requirements For Transport
B5.1 CO₂ Flow Measurements
Continuous flow meters at system entry and exit; measure pressure, temperature, flow rate, and composition.
B5.2 Pressure and Temperature Monitoring
Ensure CO₂ phase stability and detect anomalies.
B5.3 Monitoring of Energy Consumption
Meter electricity and fuels used in compression, pumping, shipping, and auxiliary systems.
B5.4 Transport Integrity Monitoring
Monitor corrosion, mechanical failure, pressure losses, and structural anomalies; ship systems monitor tank integrity and boil-off.
B5.5 Calibration and QA/QC
Calibrate per ISO or equivalent standards; use redundant systems where measurement uncertainty is material.
Chapter B6 - Data And Parameters For Transport
Table B6.1 — Transport Parameters
CO₂ entry mass CO2_entry
t CO₂
Metered at transport inlet
CO₂ exit mass CO2_exit
t CO₂
Metered at storage site
Energy for compression E_comp
MWh
Compression stages
Pumping energy E_pump
MWh
Pipeline pumping
Ship fuel Fuel_ship
tons / liters
Fuel consumed
Transport leakage LE_trans
t CO₂
Difference across system
Chapter B7 - Special Provisions
B7.1 Multi-User Transport Networks
Allocate emissions based on mass throughput or use operator-level monitoring for direct attribution.
B7.2 Temporary Storage and Buffer Tanks
Quantify any vented or lost CO₂ during buffering as leakage.
B7.3 Abnormal Operating Events
Quantify and report pipeline ruptures, emergency depressurizations, ship venting, or unexpected losses immediately.
Module C - Geological Storage
Chapter C1 - Introduction And Scope
C1.1 Purpose of the Storage Module
Establishes requirements for quantifying mass injected, contained, and permanently stored in geological formations, including site characterization, reservoir modeling, monitoring, leakage detection, and permanence demonstration.
C1.2 Scope of This Module
Applies to injection into deep formations suitable for permanent storage (saline aquifers, depleted reservoirs, basalt with mineralization, un-mineable coal seams under conditions). Governs injection operations, subsurface monitoring, well integrity, pressure management, leakage identification, and quantification over time.
C1.3 Relationship With Core Methodology and Other Modules
Module C supplements the Core methodology and must be paired with Module A or B to complete the CCS chain for PCU issuance.
Chapter C2 - Applicability Of The Geological Storage Module
C2.1 Eligible Geological Formations
Formations with sufficient porosity, permeability, depth, containment, and sealing capacity. Demonstrate suitability via geological, geophysical, geochemical, and geo-mechanical studies.
C2.2 Depth Requirements
Typically deeper than 800 meters to maintain CO₂ dense or supercritical; alternative thermodynamic demonstrations may be accepted.
C2.3 Excluded Geological Settings
Exclude shallow formations, drinking water aquifers, unstable structures, active faults with reactivation risk, or formations lacking required depth/pressure.
C2.4 Applicability to Multi-Reservoir or Multi-Well Projects
Evaluate each reservoir independently unless hydraulically connected.
Chapter C3 - Project Boundary For Storage Operations
C3.1 Spatial Boundary of the Storage Complex
Include injection reservoir, confining layers, secondary seals, structures influencing plume migration, pressure propagation area, and nearby faults/abandoned wells.
C3.2 Surface and Near-Surface Boundary
Include surface installations and surrounding areas where leakage could manifest; monitoring and observation wells must be included.
C3.3 Temporal Boundary
Monitoring begins pre-injection and continues through injection and post-injection monitoring until long-term containment is demonstrated.
Chapter C4 - Quantification Of Injected And Stored CO₂
C4.1 Measurement of Injected CO₂
The mass of injected CO₂ is determined with continuous measurements:
CO2_inj=∫FR_inj⋅dt⋅Density_(CO2,inj)
Where flow rate and density reflect actual injection conditions.
Purity and moisture adjustments must be applied identical to Module A.
C4.2 Accounting for Wellbore and Surface Losses
Meter or conservatively estimate losses from venting, blowdown, purging, and pressure-control operations; deduct from injected mass.
C4.3 Net Stored CO₂
CO2_(stored,net)=CO2_inj-LE_well-LE_geo
Where:
LE_well is leakage from injection or legacy wells
LE_geo is leakage into unintended formations or to the surface
C4.4 Mass Balance Reconciliation
The following must always hold:
CO2_delivered≥CO2_inj
C4.5 Quantification of Geological Leakage
When leakage occurs, quantification may rely on:
Direct measurement (rare but possible)
Tracer studies
Pressure and mass balance anomalies
Soil gas flux measurements
Groundwater chemistry changes
Seismic or geophysical evidence
If leakage cannot be measured directly:
LE_geo=UpperBoundEstimate(reservoir models)
PCS requires conservative quantification.
Chapter C5 - Monitoring Requirements For Geological Storage
C5.1 Monitoring Objectives
Confirm plume behavior matches models, reservoir integrity, absence of leakage, safe injection pressures, and seal integrity.
C5.2 Reservoir Monitoring
Pressure/temperature logs, plume mapping (seismic/EM), tracking of pressure propagation, and periodic geophysical surveys.
C5.3 Groundwater and Environmental Monitoring
Monitor pH, alkalinity, dissolved ions for CO₂ intrusion indicators. Surface monitoring where risk exists.
C5.4 Well Integrity Monitoring
Periodic logging (cement bond, caliper), pressure tests, annulus monitoring, and mechanical integrity tests.
Chapter C6 - Data And Parameters For Storage
Table C6.1 — Storage Parameters
Injected CO₂ mass
CO2_inj
Metered value
Reservoir pressure
P_res
Confirms containment
Plume extent
PE
Reservoir monitoring
Groundwater chemistry
GW
Detects migration
Well integrity variables
WI
Tests/logs
Geological leakage
LE_geo
Measured or modeled
Chapter C7 - Special Requirements For Storage In Hydrocarbon Reservoirs
For depleted reservoirs:
Separate storage accounting from hydrocarbon recovery phases
Demonstrate net storage when hydrocarbons are produced during injection
EOR/EGR cannot dilute storage integrity requirements.
Chapter C8 - Abnormal Conditions And Corrective Actions
On anomalies (pressure spikes, unexpected plume migration, seismic anomalies, geochemical deviations): intensify monitoring and initiate corrective measures per Core methodology.
Chapter C9 - Long-Term Storage Verification
C9.1 Post-Injection Monitoring
Confirm stabilization of plume movement/pressure, absence of leakage, and validate reservoir models.
C9.2 Criteria for Termination or Transfer of Responsibility
Transfer responsibility only when no leakage has occurred, monitoring evidences stability, reservoir behaves as predicted, pressures and plume stabilized, and VVB issues positive permanence assessment.
Chapter C10 - Role Of Storage Module In Emission Reduction Claims
Credits (PCUs) issued only for net stored CO₂. Module C determines permanent reduction; failure of storage integrity may lead to credit cancellation or replacement.
Annex A - Quantification Equations
This annex consolidates quantification equations used across Core methodology and Modules A, B, and C for VVBs and Project Developers.
A.1 Core Quantification Equations
A.1.1 Net Emission Reductions
ER_net = BE − PE − LE
Where BE = baseline emissions, PE = project emissions, LE = leakage emissions.
A.2 Module A - Capture Equations
A.2.1 Mass of CO₂ Captured
CO2_cap=∫FR_CO2⋅dt⋅Density_CO2
A.2.2 Purity Adjustment
CO2_(cap,adj)=CO2_cap×Purity_CO2
A.2.3 Moisture Adjustment
CO2_dry=CO2_(cap,adj)×(1-H2O_cont)
A.2.4 Capture Efficiency
η_cap=(CO2_dry)/(CO2_inlet )
A.2.5 Emissions From Capture Energy Use
PE_(cap,energy)=E_cap×EF_elec+Fuel_cap×EF_fuel
A.2.6 Fugitive and Venting Emissions
PE_(cap,fugitive)=∑LE_cap
A.2.7 Total Capture Emissions
PE_cap=PE_(cap,energy)+PE_(cap,fugitive)
A.3 Module B - Transport Equations
A.3.1 CO₂ Delivered to the Injection System
CO2_delivered=∫FR_(CO2,delivery)⋅dt⋅Density_(CO2,delivery)
A.3.2 Compression and Recompression Emissions
PE_comp=E_comp×EF_elec+Fuel_comp×EF_fuel
A.3.3 Pumping / Shipping Emissions
PE_(pump/ship)=E_(pump/ship)×EF_(elec/fuel)
A.3.4 Transport Leakage (Mass Balance)
LE_trans=CO2_entry-CO2_exit
A.3.5 Total Transport Emissions
PE_trans=PE_comp+PE_(pump/ship)+LE_trans
A.4 Module C - Geological Storage Equations
A.4.1 CO₂ Injected Into the Reservoir
CO2_inj=∫FR_inj⋅dt⋅Density_(CO2,inj)
A.4.2 Net Stored CO₂
CO2_(stored,net)=CO2_inj-LE_well-LE_geo
A.4.3 Total Storage Emissions
PE_stor=E_inj×EF_elec+∑(Operational" " Losses)
A.5 Consolidated Mass Balance Equation
CO2_captured≥CO2_transported≥CO2_delivered≥CO2_inj
Annex B - Monitoring Tables
A consolidated monitoring annex covering all modules.
B.1 Capture Monitoring Requirements
Table B1 — Capture Monitoring Parameters
CO₂ flow rate
Continuous metering
Continuous
Must be calibrated
CO₂ purity
GC or analyzer
Daily or continuous
Trace impurities required
Moisture content
Moisture analyzer
Daily or continuous
Adjusts mass
Capture energy
Electricity and heat metering
Monthly
Breakdown by subsystem
Fugitive emissions
Leak detection survey
Quarterly
Continuous if high risk
Venting events
Operator logs
Event-based
Must quantify volumes
B.2 Transport Monitoring Requirements
Table B2 — Transport Monitoring Parameters
CO₂ entry flow
Continuous
Continuous
At pipeline/ship inlet
CO₂ exit flow
Continuous
Continuous
At injection inlet
Transport energy
Electricity/fuel meters
Monthly
Includes recompression
Pipeline integrity
Pressure differentials, inspections
Continuous + annual
Identify leaks
Ship tank losses
Tank gauging + boil-off
Voyage-based
Applicable to ship mode
B.3 Geological Storage Monitoring Requirements
Table B3 — Storage Monitoring Parameters
Injection rate
Continuous metering
Continuous
Primary storage metric
Injection pressure
Downhole or wellhead gauges
Continuous
Critical for safety
Reservoir pressure
Observation wells
Quarterly → annual
Required for plume verification
Plume extent
Seismic / EM surveys
1–3 years
Frequency based on risk
Groundwater chemistry
Sampling wells
Semi-annual → risk-based
Detects leakage
Well integrity
Logging, annulus pressure
Annual
Required for all wells
Surface CO₂
Soil flux chambers / sensors
Risk-based
Where leakage risk exists
Annex C - Definitions & Technical References
C.1 Geological Terms
Storage complex - reservoir, caprock, confining layers, and secondary formations providing containment.
Caprock - impermeable layer preventing upward CO₂ migration.
Plume - 3D distribution of injected CO₂ within reservoir.
Pressure footprint - subsurface area affected by injection-induced pressure.
Legacy well - inactive/abandoned well intersecting storage formation.
C.2 Engineering & Operational Terms
Supercritical CO₂ - CO₂ above critical temperature/pressure enabling dense-phase transport.
Compression stage - equipment raising CO₂ pressure for transport.
Leakage - unintended CO₂ release through engineered or geological pathways.
Fugitive emissions - diffuse CO₂ releases from equipment.
C.3 Monitoring & MRV Terms
Baseline monitoring - monitoring prior to injection to establish pre-project conditions.
Verification - independent assessment by accredited VVB.
Corrective measures - actions to halt leakage or restore integrity.
C.4 References
This methodology draws on:
IPCC 2006 & 2019 Refinement
IPCC SRCCS
ISO 27914, ISO 27916
US EPA Class VI Rules
EU CCS Directive
IEA & CSLF Technical Guidelines
Relevant national subsurface permitting laws
PCS adapts these sources to deliver a global-standard, technology-neutral methodology suitable across jurisdictions.
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