PCS TG 001 Geological Storage Guidance_v1.0

Document Control

Document identification

• Document code: PCS-TG-001

• Title: Geological Storage Technical Guidance

• Scope: Guidance for site selection, characterization, capacity assessment, risk and leakage pathway analysis, monitoring (baseline/operational/long-term), well integrity, closure, and stewardship for geological CO₂ storage under PCS

• Application: Supports application of PCS CCS methodology and geological storage module and informs VVB assessment and host authority review

Version history and change log

Table DC-1. Revision history

Version	Date	Status	Summary of changes	Developed by	Approved by
v1.0	TBD	Draft	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Superseded versions

No superseded versions for v1.0.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 Technical Guidance shall be used for new project registrations and related submissions. Superseded versions shall be archived and retained for traceability and audit purposes, including for projects registered under earlier versions where applicable,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 Technical Guidance sets technical expectations and best-practice requirements to ensure geological CO₂ storage under PCS is designed, monitored, and managed in a manner consistent with long-term permanence and environmental integrity.

Scope summary

This guidance applies to geological storage activities under PCS across the full storage lifecycle and provides technical depth to support consistent interpretation of storage requirements by project proponents, VVBs, and host authorities.

Relationship to PCS standards and methodologies

This guidance supports the CCS methodology suite (including the geological storage module) and shall be read alongside applicable PCS program requirements on MRV, safeguards, and governance. Where conflict exists, the PCS Framework, Program Manual, and applicable Methodology/Module prevail.

Chapter 1 - Introduction And Purpose

1.1 Background and Rationale

1. Geological storage of carbon dioxide is a scientifically established and internationally recognized method for achieving deep, long-term reductions in atmospheric greenhouse gas concentrations. Numerous assessments by the Intergovernmental Panel on Climate Change (IPCC), the International Energy Agency (IEA), and national geological surveys confirm that deep saline formations, depleted hydrocarbon reservoirs, and other subsurface formations possess the capacity and physical properties to securely contain CO₂ over geological timeframes. Geological storage represents one of the few mitigation options capable of permanently isolating industrial CO₂ emissions at scale.

2. The Planetary Carbon Standard (PCS) builds upon these scientific foundations and provides a comprehensive regulatory and methodological system to ensure that CO₂ geological storage projects deliver measurable, durable, and verifiable climate benefits. To complement the PCS Methodology for CCS (PCS-MT-001), this Technical Guidance document provides the in-depth geoscientific and engineering requirements needed to design, verify, and maintain the integrity of geological storage sites.

1.2 Purpose of the Technical Guidance

1. This Technical Guidance establishes the mandatory scientific and engineering standards that govern geological storage under PCS. Its purpose is to ensure that all storage sites:

• Are selected based on robust geological evidence.

• Undergo detailed characterization and risk assessment.

• Are supported by predictive modeling that accurately reflects plume migration and pressure evolution.

• Have monitoring systems capable of detecting anomalies, verifying containment, and supporting corrective measures.

• Meet long-term permanence requirements necessary for carbon credit issuance.

1. While the PCS CCS Methodology defines how emission reductions and net stored CO₂ are calculated, this Guidance defines how storage sites must be designed and evaluated to satisfy those methodological requirements. Together, they form the technical and regulatory foundation of geological storage under PCS.

1.3 Scope of Application

1. This Technical Guidance applies to all geological CO₂ storage projects registered under PCS, regardless of geographic region, storage type, or industrial sector. It covers the full storage lifecycle from early screening to post-injection stewardship. Specifically, the Guidance applies to:

• Deep saline formations, including clastic, carbonate, and fractured systems.

• Depleted oil and gas reservoirs, including those with remaining hydrocarbon phases.

• Basalt formations where mineralization provides long-term trapping.

• Un-mineable coal seams where appropriate geo-mechanical conditions are verified.

• Offshore and onshore subsurface environments.

1. The Guidance is technology-neutral and can accommodate diverse injection strategies, monitoring technologies, and reservoir management approaches, provided they meet PCS integrity thresholds.

1.4 Relationship to PCS Standards and Methodologies

1. PCS-GSTG-001 must be read in conjunction with:

• PCS-MT-001 (Core CCS Methodology)

• PCS-MT-001-C (Geological Storage Module)

• PCS Safeguard & Environmental Integrity Standards

• PCS Operational Process Manual

• PCS Measurement, Reporting, and Verification (MRV) Framework

1. The Technical Guidance provides the technical basis for decisions and requirements in these documents.

2. Whenever a conflict arises:

The PCS Framework and Methodology take precedence, and this Technical Guidance shall be interpreted to support them.

1.5 Structure of This Document

1

Site Selection and Screening

Covers criteria and process for initial screening and selection of suitable storage locations.

2

Full Geological and Geophysical Characterization

Describes data acquisition, interpretation, and development of the static geological model.

3

Reservoir Modeling and Storage Capacity Assessment

Details dynamic simulation, capacity concepts, pressure limits, and operational capacity derivation.

4

Risk Assessment and Leakage Pathway Evaluation

Presents integrated risk analysis, identification of leakage pathways, and mitigation planning.

5

Monitoring System Design—baseline, operational, and long-term

Specifies monitoring objectives, techniques, baseline establishment, and adaptive monitoring.

6

Injection Operations and Well Integrity Requirements

Provides engineering standards for well design, construction, testing, and integrity management.

7

Environmental and Social Safeguard Considerations

Addresses baseline environmental assessment, community engagement, and mitigation strategies.

8

Site Closure, Verification of Permanence, and Transfer of Responsibility

Defines closure criteria, post-injection verification, and long-term stewardship conditions.

9

Documentation, Reporting, and Data Retention Requirements

Describes PDD, monitoring reports, anomaly reporting, data archiving, and transparency obligations.

1.6 Intended Audience

1. This document is intended for:

• Geological storage project developers

• Reservoir engineers and modeling specialists

• Regulators overseeing subsurface storage

• Validation and Verification Bodies (VVBs)

• Environmental and social safeguard reviewers

• Host Country authorities evaluating permitting requests

• Financial and technical partners requiring assurance of long-term integrity

1. The hybrid level of detail ensures both scientific precision and practical usability across disciplines.

1.7 Importance of Geological Storage Guidance Under PCS

1. Geological storage is fundamentally different from most carbon mitigation activities because its climate benefit depends on permanence. Unlike biological or technological solutions that may be reversible or short-lived, geological storage has the capacity to secure carbon for millennia—if properly designed and monitored.

2. This Technical Guidance ensures that PCS projects:

• Are grounded in high-quality subsurface science.

• Implement globally recognized best practices.

• Maintain long-term integrity and environmental safety.

• Provide predictable, verifiable, and durable climate outcomes.

1. It reinforces PCS’s position as a next-generation carbon standard with rigorous scientific backing and transparent performance expectations.

Chapter 2 - Site Selection And Screening

2.1 Overview of Site Selection Requirements

1. Selecting an appropriate geological storage site is the single most important determinant of long-term CO₂ storage integrity. A well-chosen site provides natural geological features—porosity, permeability, structural or stratigraphic trapping mechanisms, and robust sealing formations—that collectively ensure permanent containment. Conversely, inadequate site selection increases the probability of leakage, operational instability, induced seismicity, or environmental harm.

2. Under PCS, site selection must follow a structured, evidence-based process that evaluates geological, hydrological, geo-mechanical, and operational characteristics before a site advances to full characterization. The process must demonstrate, with credible data, that the proposed formation has the capacity and integrity necessary for injecting, distributing, and immobilizing CO₂ over the long term.

2.2 Principles Guiding Site Selection

1. The following principles guide all site-selection decisions under PCS:

2.2.1 Geological Suitability

1. The formation must have adequate depth, porosity, permeability, continuity, and structural closure to safely store CO₂ in a supercritical or dense phase. The reservoir must be overlain by a competent caprock.

2.2.2 Containment Integrity

1. The storage complex (reservoir + seals + secondary barriers) must provide long-term trapping mechanisms, including structural, stratigraphic, residual, solubility, and mineralization trapping.

2.2.3 Capacity and Injectivity

1. The formation must have sufficient pore volume and injectivity to accept the planned storage volume without exceeding pressure thresholds.

2.2.4 Safety and Environmental Protection

1. Site selection must protect groundwater, ecosystems, and communities by avoiding areas with unsuitable geological features or elevated risk.

2.2.5 Operational Practicality

1. The site must be technically accessible and viable for drilling, injection, monitoring, and long-term stewardship.

These principles underpin every analytical step in the site selection and screening process.

2.3 Preliminary Screening Criteria

1. Before detailed site characterization begins, the developer must conduct a preliminary screening using available regional and historical geological data. Preliminary screening determines whether the site warrants the time and cost of full evaluation.

2. The following criteria must be satisfied or strongly indicated:

2.3.1 Depth

1. The target formation must be deep enough to maintain CO₂ in a supercritical or dense phase. Typically, this is greater than 800 meters. Shallower formations require thermodynamic justification demonstrating equivalent containment behavior.

2.3.2 Reservoir Presence and Thickness

1. The formation must include laterally extensive, well-connected reservoir units with sufficient thickness to support plume development and storage volume.

2.3.3 Sealing Formations

1. At least one primary caprock must overlay the reservoir. Secondary seals or multi-layer sealing systems are considered advantageous.

2.3.4 Structural or Stratigraphic Traps

1. Structural closures, anticlines, domes, and stratigraphic traps increase containment reliability. Open saline formations may also be suitable if pressure management and hydrodynamic conditions are well understood.

2.3.5 Absence of Major Faults or Unacceptable Risk Features

1. Faults are not disqualifying if their behavior, sealing properties, and stress state are well characterized. Critically stressed or conductive faults require rigorous justification or avoidance.

2.3.6 Limited Presence of Legacy Wells

1. Legacy wells are potential leakage pathways. Their presence is not an automatic barrier but requires additional risk analysis and monitoring provisions.

2.3.7 Estimated Capacity and Injectivity

1. Preliminary capacity estimates must show that the formation can accommodate the intended storage volume without inducing excessive pressure or triggering geo-mechanical instability.

2. These screening criteria serve as decision gates for advancing to Chapter 3 (Full Characterization).

2.4 Sources of Data for Preliminary Screening

1. Screening relies on diverse geological data sets, including:

• Regional geological maps

• Petroleum exploration records

• Seismic survey archives

• Well logs and drilling reports

• Hydrogeological data sets

• Fault and structural inventory databases

• Academic and governmental geological studies

• Existing CO₂ or hydrocarbon field performance data

1. Where high-resolution data are lacking, preliminary acquisition of 2D seismic or shallow stratigraphic wells may be necessary before progressing.

2.5 Depth and Thermodynamic Requirements

1. Depth is a critical determinant of CO₂ phase behavior. At depths greater than ~800 meters, CO₂ typically transitions to a supercritical state, offering:

• Higher density

• Lower viscosity

• Higher storage efficiency

• More predictable flow behavior

1. If a developer proposes a shallower site, a thermodynamic and geo-mechanical justification must demonstrate:

• Stable CO₂ phase conditions despite depth

• Adequate lateral pressure margins

• No risk of CO₂ expansion-driven fracturing

1. These cases are rare and subject to stricter VVB review.

2.6 Reservoir Quality Requirements

1. Reservoir quality determines injectivity, plume migration behavior, and practical storage volume.

Key reservoir properties include:

2.6.1 Porosity

1. Porosity should be sufficiently high to provide meaningful storage capacity. Values above 10–15% are generally favorable, but site-specific variations exist.

2.6.2 Permeability

1. Permeability controls injectivity and lateral plume movement. Values above 10–100 millidarcies are often adequate but vary by lithology. Heterogeneous permeability may increase operational complexity.

2.6.3 Net Thickness and Lateral Continuity

1. Reservoir thickness and areal continuity determine the capacity for plume expansion and pressure dissipation. Multi-layer reservoirs require comprehensive connectivity modeling.

2.6.4 Fluid Properties

1. Formation water salinity, composition, and pressure gradients influence solubility trapping and flow behavior.

2.7 Seal Integrity Requirements

1. Caprock integrity is critical for preventing vertical CO₂ migration.

2. A suitable caprock must demonstrate:

• Very low permeability

• High mechanical strength

• Stability under CO₂ exposure (caprock reactivity analysis)

• Sufficient thickness

• Absence of through-going faults in critical zones

1. Laboratory tests on core samples must evaluate:

• Capillary entry pressures

• Geochemical reactivity

• Mineralogy

• Fracture properties

1. A multi-caprock sequence increases containment confidence.

2.8 Structural and Stratigraphic Considerations

1. The structural configuration influences plume movement and long-term trapping. Important considerations include:

• Folding patterns

• Fault orientation and displacement

• Seal continuity

• Anticline geometry

• Channel systems or pinch-outs

1. Closed structures (anticlines, domes) often provide robust containment zones, while open formations require pressure management planning.

2.9 Geo-mechanical Stability Requirements

1. Injection increases reservoir pressure, which can affect faults and fractures. Screening must eliminate sites prone to:

• Induced seismicity

• Fault reactivation

• Caprock fracturing

1. Regional stress fields must be understood early. If the target lies near critically stressed faults, the site may require:

• Lower injection pressures

• Real-time monitoring systems

• Advanced geo-mechanical modeling

1. Sites with unacceptable geo-mechanical risk must be rejected.

2.10 Proximity to Legacy Wells and Infrastructure

1. Legacy wells represent one of the most common leakage pathways. Screening must identify:

• The number of wells penetrating the formation

• Well age, construction quality, and abandonment methods

• Availability of historical records

1. When legacy wells are abundant and poorly documented, the site faces increased scrutiny.

2.11 Regional Hydrology and Pressure Conditions

1. Hydrological systems affect brine displacement and CO₂ migration. Important considerations include:

• Regional pressure gradients

• Connectivity with deeper or shallower aquifers

• Potential for upward brine migration

• Distance to freshwater aquifers

1. Sites with hydrological vulnerabilities require robust mitigation strategies.

2.12 Preliminary Risk Assessment

1. Before advancing to full characterization, the developer must conduct an early risk assessment that qualitatively evaluates:

• Likely leakage pathways

• Geo-mechanical hazards

• Environmental sensitivities

• Data gaps requiring early acquisition

• Potential operational issues

1. Risks must be categorized into:

• High confidence (supported by data)

• Uncertain (requires more investigation)

• High risk (potentially disqualifying)

1. This assessment determines whether the site advances to detailed characterization.

2.13 Screening-Level Suitability Decision

1. At the end of screening, the project must produce a Site Screening Report summarizing:

• Geological and structural evidence

• Preliminary capacity estimates

• Sealing integrity indicators

• Identified risks

• Data limitations

• Recommendation to proceed or discontinue

1. The Validation and Verification Body (VVB) reviews this report before the project may move to full characterization under Chapter 3.

Chapter 3 - Full Geological & Geophysical Characterization

3.1 Purpose of Full Site Characterization

1. Full geological and geophysical characterization is the central scientific process through which a project developer demonstrates that a proposed subsurface formation can safely and permanently store CO₂. While preliminary screening provides an initial indication of site potential, full characterization transforms that indication into verified geological evidence. It provides the empirical foundation upon which reservoir models are built, injection strategies are designed, monitoring systems are developed, and long-term containment is justified.

2. A suitable storage site must show that it possesses adequate reservoir quality, sealing integrity, regional stability, and structural predictability. Characterization therefore requires a coordinated integration of geological, petrophysical, geophysical, hydrogeological, and geo-mechanical data, allowing specialists to evaluate how the formation will behave during injection and after the cessation of operations. No storage project may proceed to modeling or injection design until comprehensive characterization confirms that the subsurface is capable of safely retaining injected CO₂ over long timescales.

3.2 Geological Characterization

1. Geological characterization seeks to understand the three-dimensional framework of the subsurface and the physical properties that govern fluid movement. It involves constructing a coherent geological interpretation based on lithology, depositional environment, stratigraphy, reservoir geometry, and caprock extent.

2. A complete geological description must outline how the reservoir was formed, how its properties vary laterally and vertically, and how these variations will influence CO₂ migration. The developer must analyze core samples and cuttings to define grain size, mineral composition, diagenetic features, and any lithological variations that may influence porosity or permeability. The depositional environment must be interpreted to determine whether the reservoir consists of channel sands, deltaic units, carbonate platforms, turbiditic sequences, or other facies that affect storage performance.

3. Geological characterization must also identify lateral continuity, zones of heterogeneity, barriers that might redirect the plume, and areas where reservoir thinning may limit injectivity. Every geological feature influencing fluid flow must be incorporated into the final model of the storage complex.

3.3 Petrophysical Characterization

1. Petrophysical characterization quantifies the reservoir’s pore space and flow capacity. This includes determining porosity, permeability, capillary pressure properties, and fluid saturation behavior.

2. Porosity establishes the available storage volume, and permeability governs how easily the reservoir can accept and redistribute CO₂. Both must be measured using laboratory core testing and calibrated against log-derived interpretations. The developer must understand the spatial distribution of porosity and permeability, including vertical layering and lateral anisotropy, which may significantly influence plume movement.

3. Capillary pressure curves and relative permeability relationships must be derived from appropriate experiments. These parameters determine how CO₂ displaces brine, the extent of residual trapping, and the mobility of CO₂ at various saturation levels. A full understanding of these petrophysical characteristics is essential for predicting plume behavior, designing injection rates, and assessing containment.

3.4 Geophysical Characterization

1. Geophysical characterization defines the structural and stratigraphic architecture of the storage complex using seismic and related methods. High-resolution three-dimensional seismic data are strongly preferred because they allow detailed mapping of the reservoir, caprock, faults, and potential trapping structures. Where 3D seismic is not available, two-dimensional lines may be used, although they must be supplemented with substantial well control data to mitigate uncertainty.

2. Seismic interpretation must resolve the geometry of the storage reservoir, the thickness and distribution of its units, and the continuity and quality of the overlying seal. Faults must be identified, mapped, and interpreted for their sealing behavior, orientation, throw, and potential to act as conduits or barriers. Stratigraphic features such as pinch-outs, channels, unconformities, or facies transitions must also be understood.

3. In addition to seismic data, non-seismic geophysical tools may be employed when appropriate. Electromagnetic surveys can illuminate resistivity changes associated with CO₂ saturation, while gravity and microgravity responses can help quantify mass distribution. Borehole imaging tools may reveal fracture networks and fine-scale heterogeneities. Geophysical characterization must be robust enough to support reliable reservoir modeling and long-term monitoring planning.

3.5 Structural and Fault Characterization

1. Structural analysis determines how geological forces have shaped the reservoir and seals and how these features will influence CO₂ migration. A full structural interpretation must identify all faults, folds, fractures, and structural closures within and surrounding the proposed storage complex.

2. Understanding fault behavior is critical. Some faults act as barriers, trapping CO₂ within structural compartments, while others are conductive and may provide pathways for vertical or lateral migration. The developer must determine the sealing properties of each major fault through a combination of seismic interpretation, log analysis, and, where possible, core examination.

3. It is essential to evaluate the stress state of faults to assess the risk of reactivation under elevated reservoir pressures. Faults that are critically stressed or trending toward failure represent elevated leakage risk. Structural and fault characterization must therefore integrate geological interpretation with the results of geo-mechanical analysis described later in this chapter.

3.6 Caprock Characterization

1. The caprock is the primary seal preventing CO₂ from migrating upward out of the storage reservoir. A suitable caprock must be thick, laterally continuous, mechanically strong, and possess extremely low permeability. Full characterization of the caprock requires analyzing its mineralogy, porosity, permeability, and mechanical properties.

2. Special emphasis must be placed on the capillary entry pressure, which determines the caprock’s ability to resist CO₂ buoyancy forces. Laboratory tests must evaluate how the caprock reacts when exposed to CO₂, including potential dissolution or weakening of minerals. In formations with multiple sealing layers, the interaction and cumulative sealing capacity of these layers must be explained.

3. Caprock continuity must be demonstrated through seismic mapping, ensuring there are no erosional windows, thin zones, or structural breaches that could compromise containment. Where the reservoir is overlain by several formations exhibiting sealing properties, the developer must describe the role of each in long-term containment.

3.7 Hydrogeological Characterization

1. Hydrogeological characterization examines the movement of fluids within the subsurface and determines how CO₂ injection will alter natural flow patterns. Regional flow systems must be described, including the direction of natural brine movement, hydraulic gradients, and potential hydrological connectivity between formations.

2. Understanding formation water properties is essential, including salinity, density, viscosity, and geochemical composition. These properties influence CO₂ solubility, mobility, and potential reactivity with minerals.

3. Hydrogeological characterization must also evaluate whether injection pressures could displace brine into overlying formations or protected aquifers. Evaluating vertical and lateral connectivity provides insight into pressure dissipation capacity and potential environmental risks.

3.8 Geo-mechanical Characterization

1. Geo-mechanical analysis ensures that CO₂ injection will not compromise reservoir or caprock integrity. This requires determining the in-situ stress regime, rock mechanical properties, and the potential for induced seismicity or fault reactivation.

2. The stress field must be characterized using wellbore imaging, leak-off tests, and fracture gradient analysis. Mechanical properties such as Young’s modulus, Poisson’s ratio, compressive strength, and tensile strength must be derived from laboratory testing. These properties inform the allowable injection pressure and indicate the susceptibility of the formation to fracturing.

3. Reservoir and caprock models must be developed to simulate stress changes during injection. Geo-mechanical modeling must demonstrate that injection pressures remain below critical thresholds and that no significant risk of fault activation exists.

3.9 Wellbore Characterization

1. All wells intersecting the storage complex must be thoroughly evaluated. Active wells intended for injection or monitoring must demonstrate mechanical integrity through cement bond logs, casing inspections, pressure tests, and historical records.

2. Legacy wells require special attention. These wells may have been drilled decades earlier using outdated standards, and their abandonment quality may be uncertain. They may pose significant leakage risks, especially if casing degradation, cement failures, or incomplete abandonment procedures occurred. Where legacy wells exist, the developer must evaluate their condition, proximity to the predicted plume, and need for remediation or exclusion zones.

3.10 Construction of the Static Geological Model

1. All data acquired during characterization must be integrated into a static geological model representing the structure, stratigraphy, and property distributions of the storage complex. This model must incorporate reservoir geometry, facies distribution, porosity and permeability fields, caprock thickness, and fault architecture.

2. The model must represent both best-estimate interpretations and uncertainty ranges. It must serve as the foundation for dynamic simulation in the next phase of development. The geological model must be sufficiently detailed to support injection planning, pressure management strategies, monitoring design, and risk assessments.

3.11 Data Quality and Traceability Requirements

1. Data used in characterization must meet high standards of accuracy, representativeness, and traceability. All laboratory and field data must include documentation of sampling methods, calibration certificates, analytical procedures, and quality control results. Data must be archived in formats that allow independent validation by the VVB.

2. Any data sources lacking appropriate quality documentation must be excluded or clearly identified as uncertain, with uncertainty reflected in modeling.

3.12 Site Characterization Report Requirements

1. Upon completing characterization, the developer must prepare a comprehensive Site Characterization Report. This document must include geological, geophysical, hydrogeological, and geo-mechanical interpretations and demonstrate how the site meets PCS criteria for containment, injectivity, and long-term stability. The report must identify uncertainties requiring further investigation and explain how site conditions influence monitoring design and risk management.

2. The Validation and Verification Body must evaluate this report before the project proceeds to dynamic modeling and storage capacity assessment in Chapter 4.

Chapter 4 - Storage Capacity Assessment & Dynamic Reservoir Simulation

4.1 Purpose of Storage Capacity Assessment

1. Assessing storage capacity is fundamental to determining whether a subsurface formation can safely and effectively accommodate the volume of CO₂ that a project intends to inject. Capacity assessment ensures that the reservoir possesses sufficient pore space, injectivity, and pressure tolerance to avoid operational risks, geo-mechanical instability, or long-term containment failures. While early screening provides broad estimates, the full capacity assessment must rely on detailed geological models, petrophysical data, reservoir characterization, and dynamic simulation. The objective is to move from conceptual estimates to defensible, model-supported forecasts of reservoir performance that withstand independent verification.

2. Storage capacity assessment is not merely a calculation of volumetric pore space; it is a comprehensive evaluation of how CO₂ will occupy pore space under pressure, migrate, become trapped, dissolve into formation fluids, and ultimately stabilize within the geological structure. The assessment must consider the complex interplay between fluid properties, reservoir heterogeneity, pressure evolution, and caprock integrity.

4.2 Understanding Types of Storage Capacity

1. Storage capacity exists at several conceptual levels that must be distinguished. Theoretical capacity refers to the total pore volume of the reservoir, assuming complete saturation by CO₂ under ideal circumstances. While useful as an upper bound, theoretical capacity is not realistic for operational planning. Practical capacity considers reservoir heterogeneity, pressure limitations, and injectivity constraints to develop a more attainable estimate. Dynamic capacity incorporates reservoir simulation results and provides the most realistic estimate, as it reflects the actual behavior of CO₂ flow, pressure changes, and trapping processes over time. Under PCS, dynamic capacity is the standard used for determining whether the project’s intended injection volume is feasible.

2. This hierarchical approach allows developers and VVBs to track how capacity estimates evolve as understanding of the subsurface becomes more refined. Only dynamic capacity may be used in the planning of injection rates, durations, and monitoring strategies.

4.3 Determining Pressure Constraints and Injection Limits

1. Pressure evolution within the reservoir is one of the most critical factors in storage capacity assessment. When CO₂ is injected, reservoir pressure increases, and the extent of this increase depends on injectivity, reservoir connectivity, fluid compressibility, and the rate and volume of injection. Excessive pressure can lead to caprock fracturing, fault reactivation, or fluid displacement into adjacent formations. Therefore, the developer must establish a maximum allowable injection pressure, which is typically bounded by the fracture gradient of the formation or caprock and the geo-mechanical stability of faults.

2. The determination of injection limits requires an integrated analysis of geo-mechanical and reservoir behavior. Laboratory measurements of rock strength, well-log-derived stress profiles, and in-situ tests such as leak-off or mini-frac tests must be used to define the pressure envelope within which injection can occur safely. Dynamic models must evaluate the effect of injection on pressure propagation over time and space. Sites with limited pressure dissipation capacity may require pressure management strategies such as brine extraction or multiple injection zones.

4.4 CO₂ Plume Migration and Storage Mechanisms

1. Understanding how the CO₂ plume migrates during and after injection is essential for predicting storage performance and ensuring containment. The plume moves through the reservoir according to pressure gradients, buoyancy forces, permeability anisotropy, and structural controls. The developer must model both short-term plume expansion and long-term stabilization.

2. Several mechanisms contribute to storage security. Structural and stratigraphic trapping occurs when the plume encounters impermeable geological barriers, allowing CO₂ to accumulate beneath them. Residual trapping immobilizes CO₂ in pore spaces as disconnected droplets when the plume recedes. Solubility trapping occurs as CO₂ dissolves into formation water, reducing mobility. Mineral trapping provides the most stable form of long-term storage but often operates over decades to centuries.

3. Dynamic simulations must quantify the relative contributions of these mechanisms and demonstrate that trapping processes will increase containment security over time.

4.5 Reservoir Simulation Requirements

1. Dynamic reservoir simulation is central to predicting how the reservoir will behave under injection conditions. The simulation must use the static geological model developed during characterization and incorporate petrophysical, geochemical, hydrogeological, and geo-mechanical data. The simulation must model multi-phase fluid flow, CO₂–brine interactions, pressure evolution, plume migration, and the distribution of CO₂ across trapping mechanisms.

2. The developer must justify the selection of simulation software and demonstrate that it is capable of modeling the relevant physical processes. Simulation grids must be sufficiently fine to resolve key geological features without creating excessive computational artifacts. Boundary conditions, initial conditions, and fluid property assumptions must be transparent and traceable to laboratory or field data.

3. Special attention must be given to how heterogeneity affects plume movement. Channel bodies, lenses, barriers, and anisotropy may create complex flow paths requiring advanced numerical representation. The simulation must be calibrated with historical data from analogous formations, well tests, or pilot injectivity tests where available.

4.6 History Matching and Model Calibration

1. Model calibration, often referred to as history matching, ensures that simulation results align with observed reservoir behavior. During early injection or appraisal stages, the developer must compare model predictions with measured pressure, injectivity, and fluid response data. Discrepancies must be evaluated and the geological model may require adjustment.

2. A well-calibrated model provides the foundation for long-term predictions, allowing developers and regulators to evaluate plume stability, pressure dissipation, and trapping efficiency. Calibration also reduces uncertainty and improves the credibility of risk assessments. In many regulatory regimes, models that cannot be calibrated or reconciled with field data are considered insufficient for long-term planning.

4.7 Pressure Management Strategies

1. Certain formations may exhibit limited pressure dissipation capacity. When injection volumes exceed the ability of the formation to absorb pressure, the project may be required to implement pressure management strategies. These strategies include optimized injection distribution across multiple wells, careful control of injection rates, or brine extraction to maintain acceptable pressure levels.

2. Pressure management must be evaluated through dynamic simulation. The developer must demonstrate that the reservoir will not exceed critical thresholds, that faults will not reactivate, and that caprock will remain intact. In some settings, pressure management is not optional but essential to the feasibility of the project.

4.8 Storage Efficiency and Injectivity Assessment

1. Storage efficiency reflects the fraction of available pore volume that can effectively hold CO₂ under realistic operational conditions. It depends on reservoir heterogeneity, buoyancy, residual trapping, and sweep efficiency. Developers must estimate storage efficiency using simulation-derived predictions and published efficiency factors for comparable geological systems.

2. Injectivity, the rate at which CO₂ can be introduced into the reservoir, must also be determined. Injectivity depends on permeability, pressure gradients, well configuration, and CO₂ fluid properties. Poor injectivity may require modifications to well design or reservoir management strategies. The developer must demonstrate that injectivity will remain sufficient throughout the project lifespan without creating unacceptable pressure buildup.

4.9 Uncertainty Analysis

1. All geological and reservoir models contain uncertainties due to data limitations, heterogeneity, or measurement errors. The developer must quantify uncertainties using sensitivity analysis, scenario modeling, or probabilistic methods. Uncertainty analysis must clearly show how variations in key parameters—porosity, permeability, caprock thickness, fault sealing, relative permeability, or stress fields—may affect plume migration, storage capacity, and pressure evolution.

2. The results of uncertainty analysis must guide risk assessment, monitoring design, and contingency planning. A project with high uncertainty may require additional monitoring or more conservative injection strategies.

4.10 Determination of Operational Storage Capacity

1. Operational storage capacity is the volume of CO₂ that the reservoir can accept while meeting all safety, geo–mechanical, and containment requirements. It is derived from dynamic simulation results and reflects realistic operational conditions rather than theoretical volumes.

2. Determination of operational storage capacity must consider injection duration, pressure constraints, well configuration, trapping behavior, and long-term stabilization. The developer must provide a clear justification for the proposed storage volume, supported by model outputs, sensitivity analyses, and geo–mechanical evaluations. The Validation and Verification Body will assess whether the operational capacity is scientifically defensible and whether it meets PCS requirements for safety and permanence.

4.11 Reporting Requirements for Capacity Assessment

1. The capacity assessment must be documented in a comprehensive report that includes a description of the geological model, simulation methodology, calibration process, uncertainty analysis, pressure and plume predictions, trapping mechanisms, and proposed injection strategy. The report must explain how the developer determined operational storage capacity and how risks associated with injection volumes have been mitigated. It must also demonstrate that the reservoir can safely contain the intended CO₂ volume without exceeding acceptable risk thresholds.

2. This document becomes a central part of the Project Design Document and will be scrutinized by the VVB and PCS Secretariat during validation.

Chapter 5 - Risk Assessment And Leakage Pathway Analysis

5.1 Purpose of Risk Assessment Under PCS

1. Risk assessment is the systematic process of identifying, evaluating, and managing the uncertainties and hazards associated with geological CO₂ storage. Because the success of CCS depends on the permanent containment of injected CO₂, the risk assessment must provide a defensible understanding of how the subsurface will behave, what conditions could lead to leakage, and how these risks can be minimized. This is not a regulatory formality but a scientific and operational necessity. It ensures that the storage complex has the capacity to reliably store CO₂ under expected and adverse conditions and provides the foundation for monitoring design, injection strategies, corrective action planning, and long-term stewardship.

2. Under PCS, risk assessment is a continuous function. It begins during screening, becomes rigorous during characterization, intensifies during injection, and remains active through the post-injection monitoring period. Any uncertainty that could influence containment, operational stability, or environmental impacts must be evaluated with sufficient depth to satisfy both the developer and independent verifiers.

5.2 Integrating Geological, Geo-mechanical, and Hydrological Risks

1. Risk in geological storage arises from the interaction of three domains: the geological framework that contains CO₂, the geo-mechanical behavior that governs subsurface stability, and the hydrological system that dictates how pressure and fluids move. These domains cannot be evaluated in isolation. A structurally sound reservoir may still present leakage risk if pressure accumulates beyond acceptable limits, while a hydraulically favorable formation may become problematic if local faults are critically stressed. The risk assessment must therefore answer how the reservoir will respond to injection, whether the caprock can sustain pressure changes, whether faults or fractures could transmit CO₂ or brine, and how far and how fast injected fluids may migrate.

2. This integrated approach allows the developer to identify zones of risk, determine the conditions under which they become problematic, and incorporate these findings into both reservoir models and operational planning.

5.3 Identification of Potential Leakage Pathways

1. Leakage pathways are any geological or engineered features through which CO₂ may escape the storage complex. Identifying them requires a comprehensive understanding of the reservoir, caprock, faults, fractures, wells, and surrounding formations. The risk assessment must examine all plausible migration routes for CO₂ and displaced brine, both vertically and laterally.

2. Wells drilled through the formation, whether active or abandoned, represent engineered pathways requiring special scrutiny. Their integrity depends on construction quality, casing condition, cement bonding, and historical abandonment standards. Faults may act as barriers or conduits depending on their mineralization, stress regime, and sealing properties. Caprock may contain microfractures, lateral thinning, or facies changes that reduce sealing capability. The storage formation may also be hydraulically connected to overlying or laterally adjacent aquifers.

3. Identifying these pathways is a scientific exercise requiring seismic interpretation, well log analysis, historical data review, laboratory testing, and hydromechanical modeling. The developer must describe each pathway, the mechanisms that could activate it, and the conditions under which it poses a containment threat.

5.4 Evaluation of Likelihood and Consequence of Leakage

1. Once leakage pathways are identified, the developer must evaluate both the likelihood and consequences of leakage through each pathway. Likelihood refers to the probability that CO₂ or brine will migrate along a given route under expected operating conditions. Consequence refers to the potential scale and impact of leakage, including threat to environmental receptors, groundwater systems, ecosystems, or human health.

2. This evaluation must be grounded in evidence, not assumptions. The assessment must incorporate numerical reservoir simulations, geo-mechanical models, laboratory data on caprock and fault sealing, historical well integrity information, and hydrological connectivity analyses. A pathway with low likelihood but high potential consequence may require special operational safeguards or monitoring. Conversely, a pathway with high likelihood but low consequence may require technical mitigation measures.

3. Risk evaluation helps determine which uncertainties are tolerable, which require mitigation, and which may disqualify the site if they cannot be adequately controlled.

5.5 Pressure-Related Risks and Geo-mechanical Stability

1. Reservoir pressure behavior is one of the most influential risk factors in geological storage. Excessive pressure can cause fault reactivation, caprock fracturing, or brine displacement into unintended formations. The risk assessment must therefore evaluate the entire pressure regime of the reservoir and caprock and describe how injection affects the subsurface stress field.

2. A complete assessment requires the integration of in-situ stress measurements, rock mechanical properties, fracture gradients, and dynamic simulation results. The developer must determine whether faults are critically stressed or close to reactivation and whether injection pressures approach thresholds for caprock failure. Pressure management strategies must be considered where the natural ability of the formation to dissipate pressure is limited.

3. The assessment must demonstrate, through modeling and analysis, that the chosen injection rates and durations do not compromise geo-mechanical integrity and that any pressure anomalies can be detected and mitigated.

5.6 Interaction With Legacy Wells and Engineered Structures

1. Legacy wells present elevated leakage risks because their age, construction quality, and abandonment methods often differ from modern standards. They may contain corroded casing, degraded cement, or incomplete plugs that provide direct pathways from the storage formation to overlying layers or the surface.

2. The risk assessment must identify all wells within and near the storage complex, including historical exploration wells, production wells, groundwater wells, and wells not formally documented in modern databases. The developer must evaluate the condition of each accessible well using logs, surveys, or abandonment records.

3. For wells that cannot be physically assessed, the risk assessment must rely on conservative assumptions regarding their integrity. Wells located within the predicted plume extent or pressure footprint may require pre-emptive remediation, enhanced monitoring, or exclusion from the storage area.

5.7 Potential for Brine Displacement and Groundwater Impacts

1. Injecting CO₂ into a saline formation displaces brine and may cause pressure increases that propagate outward. If uncontrolled, pressure migration may cause brine to enter formations containing potable groundwater or sensitive geological units. Even without CO₂ migration, brine displacement can pose environmental risk.

2. Risk assessment must evaluate the regional hydrological system, identify vulnerable formations, and simulate pressure propagation under various injection scenarios. The developer must demonstrate that brine displacement will not cause unacceptable impacts. Where risk exists, pressure management and enhanced monitoring may be necessary.

5.8 Risk of Induced Seismicity

1. Induced seismicity is a recognized risk in fluid injection operations, including CO₂ storage. While most induced seismic events are small and pose no hazard, the risk assessment must determine whether injection may activate faults or fractures capable of generating seismic events. This requires analysis of the local and regional stress field, fault orientations, mechanical properties, and historical seismicity.

2. Dynamic simulation must incorporate poro-elastic responses to pressure changes, and geo-mechanical models must evaluate slip tendencies of faults. Sites located near geologically sensitive areas may require conservative operational limits or continuous micro-seismic monitoring.

5.9 Integration of Risk Assessment Into Monitoring and Operational Design

1. Risk assessment is not an isolated analytical exercise; it directly informs monitoring design and operational strategy. The developer must demonstrate how identified risks influence monitoring frequency, monitoring technology selection, injection pressures, well placement, plume tracking requirements, and corrective action provisions.

2. High-risk zones must receive more intensive monitoring. Identified leakage pathways must be instrumented or observed using appropriate geophysical or geochemical methods. Operational plans must reflect pressure limits established through risk assessment. The monitoring plan developed later in this guidance must align with the results of the risk assessment and provide verifiable evidence that risks are controlled.

5.10 Uncertainties and Their Management

1. All subsurface evaluations involve uncertainties arising from data limitations, geological variability, or model approximations. The risk assessment must explicitly identify uncertainties, describe their potential effects on containment and injectivity, and evaluate how they may influence plume behavior or leakage potential.

2. Uncertainty does not invalidate a storage project, but unmanaged or unquantified uncertainty may undermine its safety. The developer must demonstrate strategies for reducing uncertainty through additional data acquisition, improved modeling, pilot injection, or enhanced monitoring.

3. The Validation and Verification Body will assess whether uncertainty has been handled with sufficient rigor to justify moving forward.

5.11 Risk Assessment Documentation Requirements

1. The risk assessment must be documented in a comprehensive and transparent report. This report must describe how risks were identified, what data and models were used to evaluate them, how likelihood and consequences were estimated, and how results guide operational decisions. The report must also describe mitigation strategies, corrective action triggers, and monitoring implications.

2. This document forms a core part of the Project Design Document and is subject to rigorous VVB evaluation. No project may advance to injection unless the risk assessment demonstrates that risks are acceptable, manageable, and aligned with PCS integrity requirements.

Chapter 6 - Monitoring Framework: Baseline, Operational, And Long-Term Phases

6.1 Purpose of Monitoring in Geological CO₂ Storage

1. Monitoring is the continuous process that ensures injected CO₂ remains contained within the storage complex and that reservoir behavior aligns with predictions made during characterization and dynamic modeling. The monitoring framework must provide early detection of anomalies, validate model assumptions, support risk management, and demonstrate permanence of storage over time. Its design must be directly informed by the geological understanding of the storage site, the identified risks, and the expected evolution of the CO₂ plume and pressure field. Under PCS, monitoring is not merely a reporting requirement; it is a scientific and operational safeguard that underpins the integrity of the carbon units issued.

6.2 Principles Guiding the Monitoring Framework

1. The monitoring framework rests on several foundational principles. Monitoring must be risk-based, meaning that areas or processes associated with higher uncertainty or potential leakage must be monitored with greater frequency or precision. Monitoring must be capable of detecting deviations from modeled plume movement, unexpected pressure changes, or geochemical signatures indicative of leakage or migration outside the intended storage complex. The framework must also be adaptive, evolving in response to new data and insights gained during injection and post-injection phases. Finally, monitoring must be verifiable, relying on calibrated instruments, traceable data, and methods that can withstand independent validation by VVBs.

6.3 Baseline Monitoring Requirements

1. Baseline monitoring establishes the pre-injection conditions of the reservoir, overburden formations, groundwater systems, and near-surface environment. This baseline provides the reference against which all future changes are evaluated.

2. Reservoir conditions such as initial pressure and temperature, fluid composition, natural seismicity levels, and existing hydrological gradients must be measured and documented. Seismic surveys, whether two-dimensional or three-dimensional, must be conducted to map the reservoir and caprock prior to CO₂ injection. Groundwater chemistry must be assessed to establish natural variability in pH, alkalinity, dissolved ions, and other chemical markers. Near-surface measurements such as soil gas flux or atmospheric CO₂ concentrations are required when there is any possibility that surface monitoring could be needed during the operational or post-injection period.

3. Baseline monitoring ensures that any subsequent variation, whether in reservoir behavior, seismicity, groundwater chemistry, or surface emissions, can be attributed to injection activity rather than natural background processes.

6.4 Monitoring During Injection Operations

1. Operational monitoring is intended to track how the reservoir responds to CO₂ injection in real time. Injection rates, injection pressures, and cumulative injected volumes must be recorded continuously. These measurements confirm that the injection strategy remains within the pressure and operational limits defined during characterization.

2. Monitoring must allow the operator to observe the evolution of the CO₂ plume. Depending on the sensitivity of the reservoir to seismic signals, time-lapse seismic imaging may be used to visualize the plume’s spatial expansion. In formations where seismic response is less reliable, other geophysical or geochemical techniques may be required. Pressure monitoring wells positioned strategically around the injector must measure how pressure propagates through the formation, providing vital data to validate reservoir models. These data inform both plume prediction and geo-mechanical stability assessments.

3. Micro-seismic monitoring may be necessary where fault stability is a concern. Even small seismic events can indicate stress changes that may require operational adjustments. Similarly, monitoring of groundwater formations must continue during injection to detect early signs of brine displacement or geochemical alteration that could signal upward fluid migration.

4. Operational monitoring must be capable of identifying anomalies promptly. If unexpected pressure increases, plume deviations, or geochemical shifts occur, injection rates may need to be adjusted or halted while the underlying cause is investigated.

6.5 Integration of Monitoring With Reservoir Modeling

1. Monitoring data collected during injection must be used to update and improve reservoir models. This process ensures that predictions remain realistic as new information emerges. Periodic recalibration helps refine estimates of reservoir permeability, heterogeneity, caprock behavior, and plume distribution.

2. When monitoring indicates discrepancies between modeled and observed behavior, the developer must analyze the cause, revise model inputs, and adjust operational strategies if necessary. Modeling and monitoring are iterative processes; each informs the other to ensure that the project remains within the containment envelope defined by risk assessment.

This integration is essential for establishing long-term confidence in storage integrity.

6.6 Monitoring for Leakage Detection

1. Leakage monitoring is a specific subset of monitoring designed to detect unintended migration of CO₂ or brine. The strategy for leakage detection must be tailored to the risk profile identified in Chapter 5. Potential leakage pathways such as faults, fractures, legacy wells, and permeable overburden formations must be prioritized in the design of leakage detection systems.

2. Downhole monitoring instruments must detect pressure or temperature anomalies that could indicate upward migration. Groundwater monitoring wells situated above the reservoir or within vulnerable aquifers must measure chemical indicators such as dissolved CO₂, pH shifts, or alterations in ionic composition. In some cases, tracer compounds may be used to distinguish CO₂ from natural background variations.

3. At the surface, soil gas analyses or atmospheric CO₂ monitoring may be established where near-surface leakage is plausible. Where surface deformation is a risk, satellite-based or ground-based geodetic techniques, such as InSAR or GPS, may be used to detect minute changes in surface elevation caused by subsurface pressure changes.

4. The monitoring plan must ensure that any leakage is detected at the earliest possible stage, even if the quantities involved are small.

6.7 Monitoring of Injection Wells and Well Integrity

1. Injection wells and monitoring wells are engineered structures that must remain mechanically and physically intact throughout injection and post-injection operations. Monitoring of well integrity involves periodic logging, pressure testing, cement bond evaluation, casing inspection, and annulus pressure measurement.

2. An increase in annulus pressure, unexpected pressure communication between well segments, or evidence of fluid migration along the casing or cement interface may indicate a well integrity issue that must be addressed immediately. The monitoring plan must specify the frequency and methods of well integrity assessments and outline how anomalies are to be interpreted and remedied.

3. Well integrity monitoring is essential because wells represent the most direct and well-documented potential leakage pathway in geological storage projects.

6.8 Long-Term Monitoring After Injection Ceases

1. Once injection operations end, monitoring must continue to confirm that the reservoir stabilizes and that CO₂ becomes increasingly immobilized through residual, solubility, or mineral trapping. Post-injection monitoring must be designed to demonstrate that plume movement slows significantly, pressure dissipates toward pre-injection levels, and no leakage occurs.

2. Reservoir pressure measurements are essential during this stage, as pressure decline is a key indicator of stabilization. Periodic geophysical surveys, whether seismic or alternative methods, must be conducted to track the position and shape of the CO₂ plume. Groundwater monitoring must continue long enough to demonstrate chemical stability and absence of CO₂ migration.

3. The duration of this phase depends on site-specific conditions. Monitoring may be reduced gradually as evidence accumulates that the reservoir has reached a stable state. However, reduction must be justified using model predictions validated against monitoring results.

6.9 Adaptive Monitoring and Continuous Improvement

1. The monitoring framework must be adaptive rather than static. As new data are collected, the developer must evaluate whether they indicate greater certainty, reveal new risks, or necessitate changes to monitoring frequency or methods. Unexpected behavior, even if not immediately threatening containment, may signal underlying geological or geo-mechanical complexities that must be better understood.

2. Adaptive monitoring ensures that monitoring intensity and focus remain appropriate throughout the project lifecycle. It also aligns monitoring efforts with evolving scientific understanding, regulatory expectations, and operational realities.

6.10 Data Quality, Instrumentation, and Traceability

1. All monitoring instruments must be suitable for the subsurface environment, resistant to CO₂ exposure, and calibrated at appropriate intervals. Data must be traceable to specific instruments and time-stamped to allow reconstruction of time series. Quality assurance and quality control procedures must be documented clearly.

2. The developer must ensure redundancy in critical measurement systems to avoid data loss. Any substitutions for missing data must be conservative, justified, and documented in the Monitoring Report.

6.11 Reporting and Transparency Requirements

1. Monitoring results must be reported regularly through the PCS Monitoring Report. The developer must summarize operational conditions, injection volumes, reservoir responses, plume movement indicators, groundwater monitoring results, and any observed anomalies. The report must also describe how data were used to update models and guide operational decisions.

2. Transparency in monitoring is essential to verify long-term containment and to maintain confidence in the environmental integrity of PCS-issued carbon units.

Chapter 7 - Injection System Design And Well Integrity Requirements

7.1 Purpose of Injection System and Well Integrity Requirements

1. The integrity of the injection system is fundamental to the safety and reliability of geological storage. Wells form the engineered pathway by which CO₂ is introduced into the subsurface and, at the same time, represent one of the most direct potential routes for leakage. Ensuring well integrity is therefore central to demonstrating the long-term performance and security of a storage project. Under PCS, injection well design, construction, operation, and post-injection management must adhere to rigorous engineering and geo-mechanical standards that maintain pressure control, prevent fluid migration along the wellbore, and preserve containment throughout the project’s lifecycle.

7.2 Principles of Injection Well Design

1. Injection wells must be designed to withstand the unique thermal, chemical, and mechanical stresses associated with CO₂ injection. Supercritical or dense-phase CO₂ can react with steel, cement, and certain rock minerals, and injection pressures may induce changes in subsurface stress conditions. To ensure resilience, the well design must incorporate materials and construction techniques that mitigate the potential for corrosion, chemical degradation, thermal cycling, and mechanical deformation.

2. The well design must also support operational requirements. It must maintain the ability to introduce CO₂ at the required rates and pressures, resist collapse or deformation, and allow for reliable measurement of flow and pressure. The architecture of the well, including casing strings, cement placement, tubing materials, packers, and safety valves, must be chosen with full understanding of site-specific geo-mechanical and geochemical conditions.

7.3 Construction Standards and Material Requirements

1. The selection of casing, tubing, and cement materials must be based on compatibility with CO₂ under expected pressure, temperature, and chemical conditions. Carbon steel may be acceptable in some settings, but environments with high water content or corrosive impurities require corrosion-resistant alloys or protective coatings. Cement formulations must be chosen to minimize CO₂-induced degradation, maintain bond strength over time, and resist chemical alteration that could reduce sealing effectiveness.

2. All cementing operations must ensure complete isolation of permeable formations. Cement must be placed to prevent micro-annuli, channeling, or gaps that could create pathways for CO₂ migration. Verification through cement bond logging and other diagnostic tools is essential. The construction process must demonstrate that each well meets its design specifications and integrity criteria before CO₂ injection begins.

7.4 Injection Well Completion and Operational Architecture

1. The completion design must enable efficient CO₂ injection while ensuring wellbore stability. Tubing strings must be sized and rated to handle dense-phase CO₂ and withstand thermal stresses associated with changes in injection temperature. Mechanical packers or similar devices must isolate the annulus and prevent fluid movement between well sections. Safety valves and pressure-control devices must be installed to allow for rapid response in the event of an anomaly.

2. The well must be equipped with instrumentation capable of continuous measurement of injection rates, tubing and casing pressures, wellhead temperatures, and other parameters relevant to operational safety and monitoring. The design must allow for intervention or re-entry should remedial work become necessary at any point during the project.

7.5 Pre-Injection Testing and Verification

1. Before CO₂ injection begins, the well must undergo comprehensive integrity testing. Pressure tests, leak-off tests, annulus pressure checks, mechanical integrity tests, and cement evaluation logs must be conducted to verify that the well meets performance requirements. Any anomalies must be resolved through remedial work, and the well must not be approved for injection until all integrity criteria are satisfied.

2. These tests establish a baseline for future integrity assessments. They ensure that subsequent deviations in pressure, temperature, or mechanical response can be evaluated accurately against known pre-injection conditions.

7.6 Operational Integrity and Monitoring During Injection

1. During injection, the well is continuously exposed to conditions that can challenge its integrity. High injection pressures, thermal fluctuations, chemical exposure, and cyclic loading may affect casing, tubing, and cement. Continuous monitoring of wellhead and downhole pressures, temperatures, injection rates, and annulus conditions is essential for detecting early signs of degradation or abnormal behavior.

2. Any unexplained increase in casing or annulus pressure, deviation from expected pressure-rate relationships, or irregular fluid behavior may indicate developing integrity issues. Such anomalies must be investigated immediately, with injection paused or adjusted if necessary to maintain safety. Data collected from operational monitoring must be integrated with reservoir modeling and risk assessment to ensure consistency between observed and predicted behavior.

7.7 Integrity of Monitoring Wells and Observation Infrastructure

1. Monitoring wells play a crucial role in tracking reservoir pressure, fluid chemistry, geochemical changes, and potential leakage. These wells must therefore meet the same construction standards as injection wells, even though they may not be subjected to the same operational pressures. Their design must prevent cross-flow between formations and ensure that any detected chemical or pressure changes represent genuine subsurface behavior rather than artifacts of wellbore leakage.

2. Monitoring wells must be placed strategically based on reservoir modeling and risk assessment. Their placement should allow early detection of plume migration or pressure propagation beyond desired boundaries. Integrity tests similar to those conducted for injection wells must be performed regularly throughout the project’s operational and post-injection phases.

7.8 Management of Legacy Wells and Wellbore Remediation

1. Legacy wells represent a major risk factor for geological storage projects because they may contain degraded casing, poor-quality cement, or incomplete abandonment measures. Such wells may create vertical conduits that bypass natural sealing formations. The developer must locate and evaluate all legacy wells within the storage complex and pressure footprint, including wells not documented in modern records. When integrity concerns exist, the developer may need to perform remedial work such as re-cementing, plugging, or complete re-abandonment.

2. If a legacy well is located in a position that threatens containment and cannot be remediated to modern standards, the developer must either redesign the injection strategy or exclude that region from the storage complex.

7.9 Managing Thermal and Chemical Effects of CO₂ on Well Integrity

1. Injected CO₂, particularly when containing water or impurities, can react with steel and cement to form corrosive environments. Temperature changes during injection and shut-in periods may also induce thermal stresses that affect casing integrity. The risk assessment must therefore incorporate geochemical modeling to predict how materials will behave under prolonged exposure to CO₂.

2. Cooling of the wellbore during injection can create tensile stress if temperature drops significantly. Upon shut-in, the temperature may increase and create compressive stress. These cycles can weaken materials over time. The injection system must be designed to manage such temperature fluctuations, either through fluid conditioning or controlled ramping of injection rates.

7.10 Post-Injection Well Integrity and Long-Term Stability

1. Well integrity management does not end when injection stops. Pressure redistribution, fluid migration, and geochemical processes continue to influence the wellbore environment. Monitoring of wellbore pressures, annulus conditions, and cement bonds must continue through the post-injection monitoring period defined in the PCS Methodology.

2. Over time, CO₂ may dissolve into formation water, reducing free-phase mobility but potentially altering wellbore conditions. Cement carbonation reactions may strengthen or weaken bond structures depending on mineralogy. Developers must track these processes to ensure that no long-term leakage pathways develop. If integrity concerns arise, corrective measures must be implemented promptly in accordance with the PCS leakage management requirements.

7.11 Documentation, Reporting, and Traceability Requirements

1. All aspects of injection well design, testing, monitoring, maintenance, and remediation must be fully documented. This includes design specifications, material selections, cementing records, integrity test results, operational monitoring data, and any repairs conducted during the project's lifespan. These records must be preserved for the entire duration of the project, including the post-injection monitoring period.

2. Documentation is essential for validation and verification, regulatory oversight, and future stewardship. The transparency and completeness of well-related records help ensure that long-term storage security can be demonstrated conclusively long after injection has ceased.

Chapter 8 - Environmental And Social Assessment

8.1 Purpose of Environmental and Social Assessment

1. Geological CO₂ storage projects operate within complex environmental and societal contexts. While the subsurface components are chiefly technical and geoscientific in nature, their potential interactions with groundwater resources, ecosystems, surface environments, and communities require deliberate and structured evaluation. The purpose of the environmental and social assessment is to ensure that CO₂ storage activities do not compromise protected resources, disproportionately affect vulnerable groups, or introduce unacceptable risks to public health or safety. Under PCS, environmental and social considerations are integral to project design; they are not external add-ons. The assessment provides a framework for anticipating impacts, designing mitigation strategies, engaging stakeholders transparently, and ensuring that storage projects contribute positively to sustainable development.

8.2 Baseline Environmental Conditions

1. A comprehensive understanding of the pre-project environmental conditions forms the foundation for assessing potential impacts. The baseline assessment must characterize groundwater systems, surface water bodies, soil geochemistry, vegetation, wildlife habitats, and any sensitive or protected ecological zones in the project area. Groundwater analysis must describe aquifer depth, flow direction, water chemistry, and natural variability of indicators such as pH, salinity, dissolved minerals, and trace gases. Soil characteristics and natural CO₂ flux patterns must also be documented to provide a benchmark for detecting any post-injection changes. Ecological assessments must identify species dependent on the local environment, migration patterns, breeding grounds, and areas of ecological vulnerability.

2. The baseline assessment is necessary because it distinguishes natural variations from project-related effects, ensuring that monitoring results in later phases can be correctly interpreted.

8.3 Protection of Groundwater Resources

1. Protection of groundwater is one of the most critical environmental obligations of CO₂ storage projects. Injected CO₂, if not adequately contained, may migrate upward, dissolve into groundwater systems, or mobilize minerals that alter water chemistry. Brine displacement caused by injection pressure may also affect freshwater aquifers even without CO₂ breakthrough.

2. The assessment must evaluate the separation between the storage reservoir and potable or protected aquifers, including the thickness, integrity, and lithological properties of intervening formations. Hydrogeological analyses must describe natural flow paths, hydraulic connectivity, and vertical permeability to determine whether pressure increases could propagate toward shallow systems. When risks are identified, the assessment must recommend protective measures such as pressure management, enhanced monitoring, or buffer zones. Projects must demonstrate that groundwater quality will remain protected throughout injection and post-injection periods.

8.4 Soil, Surface Water, and Ecosystem Considerations

1. CO₂ leakage at or near the surface, though unlikely when subsurface systems are properly engineered, may alter soil chemistry or affect vegetation health. Elevated CO₂ concentrations in soil can disrupt root respiration, and in extreme cases may cause vegetation stress or localized die-off. Similarly, if CO₂ discharges into surface water bodies, it can alter pH and affect aquatic organisms.

2. The environmental assessment must examine these pathways and characterize any potential ecological sensitivities in the project region. It must describe vegetation patterns, land uses, surface hydrology, and seasonal environmental variations. Even in the absence of identified leakage risks, the assessment must provide sufficient environmental context to support the monitoring program designed in later chapters. In ecosystems with high sensitivity, the project may need additional mitigation measures or more frequent environmental checks.

8.5 Management of Brine Displacement Risks

1. CO₂ injection displaces formation brine, potentially causing upward or lateral pressure propagation. If unmanaged, this may force brines into intermediate or shallow formations, potentially degrading groundwater quality or affecting sensitive ecosystems. The assessment must describe the regional hydrological regime and evaluate whether pressure propagation could intersect with protected aquifers or surface environments.

2. Where brine displacement risks are moderate or high, the project must design a pressure management strategy as part of its operational plan. This may include controlled brine extraction, optimization of injection rates, or selective placement of monitoring wells in areas where pressure influence is expected to be strongest. Projects must show that the natural or managed hydrological system can accommodate injection volumes without causing unacceptable impacts.

8.6 Community Engagement and Social Acceptability

1. CO₂ storage projects intersect with community interests, even when most infrastructure is located underground. Community acceptance depends on transparent communication, credible safety measures, and clear demonstration that the project will not negatively affect local livelihoods or environmental health. The social assessment must therefore explore the human context in which the project is being developed. It must describe population characteristics, land use patterns, cultural or heritage sites, and any existing community concerns related to industrial or energy developments.

2. Engagement must begin early and continue throughout the project lifecycle. Communities must be informed about the risks and benefits of CO₂ storage, the safeguards in place, and the emergency response measures that apply even if the likelihood of an incident is extremely low. A well-conducted social assessment must not only identify potential impacts but also guide strategies to strengthen trust, accessibility, and transparency in project communications.

8.7 Environmental and Social Impact Mitigation

1. The assessment must describe how the project will mitigate any identified risks. Mitigation measures may involve operational limits, enhanced groundwater monitoring, additional environmental safeguards, modified well design, or adjustments to injection rates. For social impacts, mitigation may include community outreach programs, grievance mechanisms, land access arrangements, or compensation frameworks when appropriate.

2. The mitigation strategy must be grounded in scientific understanding and stakeholder consultation. It must demonstrate that, even under conservative assumptions, the project will maintain environmental safety and social alignment throughout its operational and post-injection phases. Mitigation must also be dynamic; as new information emerges during monitoring, the strategy must be updated to reflect improved understanding.

8.8 Emergency Preparedness and Response Considerations

1. Although geological storage projects are designed to minimize the likelihood of incidents, the environmental and social assessment must consider the practicality and adequacy of emergency response systems. This includes evaluating the readiness of local authorities, availability of monitoring technologies, communication protocols, and the project’s ability to halt or modify injection activities in response to unexpected conditions.

2. The assessment must demonstrate that emergency procedures are aligned with the nature of potential risks and that responsible personnel have the ability to respond effectively. A technically sound emergency response plan reinforces community confidence and ensures compliance with PCS governance requirements.

8.9 Integration With PCS Safeguards and Sustainable Development Requirements

1. The environmental and social assessment must align with PCS safeguard principles, which include protecting sensitive ecosystems, preventing disproportionate harm to vulnerable populations, and ensuring that projects support sustainable development objectives. The assessment must show how the storage project contributes to environmental protection, climate mitigation, and local or regional sustainability priorities.

2. This integration ensures that geological storage projects are not evaluated solely on their technical performance but also on their broader environmental and social contributions. Storage projects that fail to demonstrate alignment with PCS safeguard principles cannot proceed to registration.

8.10 Documentation and Reporting Requirements

1. The environmental and social assessment must be documented in a dedicated report that forms part of the Project Design Document. The report must clearly describe baseline conditions, potential environmental impacts, community considerations, identified risks, mitigation strategies, and any required follow-up actions. It must also outline how the project will continue to engage with stakeholders throughout its lifecycle. The assessment must be transparent, traceable, and sufficiently detailed to enable independent evaluation by VVBs and PCS Secretariat reviewers.

Chapter 9 - Site Closure, Post-Injection Verification, And Long-Term Stewardship

9.1 Purpose of the Closure and Post-Injection Phase

1. The closure and post-injection phase marks the transition of a CO₂ storage project from active operations to long-term stabilization and stewardship. Although injection ends, the responsibility to ensure safe containment continues. Pressure redistribution, brine equilibration, geochemical reactions, and plume stabilization unfold over timescales longer than the injection period itself. The objective of this chapter is to define the technical and procedural requirements that govern this phase so that the geological formation can be demonstrated to securely contain CO₂ without ongoing operational intervention.

2. Successful closure requires conclusive evidence that reservoir behavior aligns with modeled predictions, that the CO₂ plume has entered a stable or predictably stabilizing state, that pressure has dissipated to safe levels, and that no leakage is occurring. The closure phase therefore represents a scientifically rigorous process that confirms the long-term success of the project.

9.2 Transition From Injection to Closure

1. The transition to closure does not occur immediately when the last volume of CO₂ is injected. Instead, the developer must demonstrate that injection has ceased permanently and that the reservoir has begun the natural process of pressure relaxation. Injection wells must be shut in according to approved procedures, and operational data—such as final injection pressure, rates, and cumulative volumes—must be preserved and analyzed.

2. During this transition, monitoring remains at full operational intensity because injection-related anomalies may appear after injection stops. Reservoir pressures may continue to rise for short periods due to delayed equilibration or thermal effects. The transition phase must therefore be planned and closely observed, with the understanding that injection cannot resume without regulatory approval once closure procedures begin.

9.3 Post-Injection Monitoring Objectives

1. The primary objectives of post-injection monitoring are to verify the stabilization of the CO₂ plume, confirm reservoir pressure decline, ensure that trapping mechanisms are progressing as predicted, and demonstrate the absence of leakage through faults, wells, or other pathways. Monitoring during this period must be capable of capturing slow but meaningful changes in subsurface conditions.

2. Although the frequency of monitoring may eventually decline as confidence increases, post-injection monitoring must initially mirror operational monitoring in its rigor. Over time, as evidence accumulates that the reservoir is behaving safely and predictably, the monitoring intensity may be reduced, provided that such reductions are justified using site-specific data and validated model predictions.

9.4 Demonstrating Plume Stabilization

1. Plume stabilization is one of the most important conditions for closure under PCS. Stabilization refers to the point at which the CO₂ plume no longer migrates significantly and instead becomes immobilized within structural traps, residual saturations, and dissolved phases. The developer must demonstrate through repeated monitoring that plume movement decreases in velocity and extent, and that no unexpected migration pathways are active.

2. Time-lapse seismic imaging, pressure observations, and geochemical monitoring all contribute to confirming plume behavior. Reservoir models must be updated with new data and must show that the plume trajectory aligns with predicted outcomes. If model predictions and monitoring results diverge materially, additional investigation and potentially a revised model may be required before stabilization can be claimed.

9.5 Demonstrating Pressure Decline and Geo-mechanical Stability

1. After injection ceases, reservoir pressure should begin to decrease as CO₂ redistributes and brine flows adjust to the new conditions. Demonstrating pressure decline is essential because sustained overpressure could compromise caprock integrity or induce geo-mechanical stress.

2. Pressure measurements from monitoring wells must be evaluated over time to confirm that pressure is trending downward toward pre-injection or stable equilibrium conditions. Pressure decline must be consistent with model predictions updated using post-injection data. If pressure behaves unexpectedly, the developer must analyze whether the deviation indicates incomplete understanding of reservoir connectivity, heterogeneity, or boundary conditions. In extreme cases, pressure management interventions may be required.

3. Geo-mechanical assessments conducted during the operational phase must be repeated or updated to confirm that injection has not triggered long-term fault reactivation risks or new stress conditions. A stable geo-mechanical environment is a prerequisite for moving toward closure.

9.6 Confirmation of Containment and Absence of Leakage

1. The project must demonstrate conclusively that no CO₂ leakage is occurring. This requirement applies to both geological and engineered leakage pathways. Monitoring wells, surface surveys, groundwater sampling, and geophysical imaging must all indicate stability and the absence of CO₂ outside the designated storage complex.

2. Groundwater monitoring must show that pH, alkalinity, dissolved CO₂, and other chemical indicators remain within natural baseline ranges or follow expected trends due to long-term geochemical processes rather than leakage. Surface monitoring, where required, must confirm that soil gas CO₂ concentrations or flux patterns do not deviate from baseline conditions.

3. If any early warning signals arise—such as anomalous pressure behavior, unexpected geochemical changes, or irregular seismic responses—the developer must investigate thoroughly and, if necessary, implement corrective measures. Only when all evidence confirms that containment is secure may the project proceed toward closure certification.

9.7 Closure of Injection Wells and Monitoring Infrastructure

1. Well closure is a critical procedure during site closure. Injection wells must be permanently abandoned using techniques that ensure long-term zonal isolation. Cement plugs must be placed at strategic depths, casing sections may be removed or sealed, and bonding integrity must be verified repeatedly. The abandonment design must account for the long-term geochemical effects of CO₂-rich environments on cement and casing materials.

2. Monitoring wells may be retained for extended observation or may be abandoned depending on their relevance to post-injection monitoring. Wells selected for abandonment must follow the same rigorous standards applied to injection wells. Wells retained for monitoring must be maintained and tested periodically to ensure they do not themselves create leakage pathways.

9.8 Criteria for Site Closure Under PCS

1. Site closure may be initiated only when the developer can demonstrate that the reservoir is behaving in a stable and predictable manner and that risks identified in the assessment process have been mitigated or reduced to acceptable levels. The key criteria for closure include evidence of plume stabilization, prolonged pressure decline toward equilibrium, absence of leakage, acceptable geo-mechanical conditions, and a strong alignment between model predictions and monitored data.

2. Closure decisions also require confirmation that all wells have been abandoned or maintained according to approved standards, that monitoring programs have generated adequate evidence of safety, and that no outstanding corrective actions remain. The developer must compile this evidence into a formal Closure Verification Report for evaluation by the VVB and the PCS Secretariat.

9.9 Post-Closure Monitoring and Verification

1. Even after initial closure is accepted, a period of post-closure monitoring is required to ensure that reservoir stabilization continues and that no late-developing anomalies arise. The duration and intensity of this phase depend on site-specific geological conditions, model uncertainty, residual risks, and the performance demonstrated during earlier phases.

2. Monitoring during this period typically focuses on reservoir pressure, plume position, groundwater chemistry, and potential geo-mechanical indicators. As confidence grows, monitoring may shift from active to standby modes, eventually reaching a point at which routine monitoring is no longer required. However, the developer must remain prepared to respond if new data suggest emerging risks.

9.10 Conditions for Transfer or Termination of Long-Term Stewardship

1. At the conclusion of the post-closure monitoring period, the developer may request transfer or termination of long-term stewardship responsibilities. PCS may approve this transition only when the project provides strong, verified evidence that the stored CO₂ is permanently contained and will remain so without ongoing operational management.

2. To approve transfer, PCS requires reservoir models that show long-term stability, monitoring data that confirm the absence of leakage or adverse trends, and documentation demonstrating that all wells have been properly closed or maintained. The final decision is based on a comprehensive evaluation of technical, environmental, and risk-based evidence.

3. Once PCS confirms that all criteria have been met, long-term responsibility may shift according to jurisdictional arrangements or conclude entirely if the system no longer requires oversight. This marks the final stage in the lifecycle of a geological storage project.

9.11 Documentation and Reporting Requirements

1. Throughout closure and post-injection phases, documentation must be meticulous and transparent. All monitoring results, model updates, well abandonment reports, geochemical analyses, geophysical surveys, and corrective action logs must be archived and maintained for auditability. The Closure Verification Report must provide a complete narrative of reservoir behavior from the start of injection to the final stage of stabilization, integrating both predictive and observational evidence.

2. Clear, well-documented reporting supports independent validation and strengthens confidence in the long-term integrity of the storage project, ensuring the credibility of PCS-issued carbon units.

Chapter 10 - Documentation, Reporting, And Data Retention Requirements

10.1 Purpose of Reporting and Documentation Under PCS

1. Geological CO₂ storage is a long-duration undertaking that requires clear, accurate, and verifiable records spanning from project planning to post-injection stewardship. Reporting and documentation serve as the backbone of transparency and accountability. They allow the PCS Secretariat, Validation and Verification Bodies (VVBs), Host Country Authorities, and other stakeholders to evaluate whether a storage project remains safe, compliant, and aligned with its modeled performance. Because geological storage involves processes that unfold over decades, high-quality documentation is essential not only for real-time oversight but also for reconstructing site history and supporting future stewardship.

2. Under PCS, reporting is not simply the submission of technical data; it is a continuous demonstration of responsible management, scientific rigor, and environmental integrity.

10.2 Requirements for Project Design Documentation

1. Before injection begins, the developer must compile a comprehensive Project Design Document (PDD) that integrates the results from geological characterization, risk assessment, reservoir simulation, monitoring design, and injection planning. This document must present a clear narrative describing the site, its suitability, and the technical basis for injection. The PDD functions as the foundational reference against which all subsequent performance is evaluated.

2. It must include descriptions of reservoir and caprock properties, detailed geological models, results from seismic interpretations, geo-mechanical analyses, hydrological assessments, and planned injection strategies. The PDD must also articulate the monitoring program, explaining how each monitoring activity addresses specific risks identified earlier in the assessment process.

10.3 Operational Reporting During Injection

1. During injection, the developer must submit periodic reports detailing injection rates, cumulative injected volumes, pressure and temperature conditions, well performance, and any operational adjustments. These reports must interpret the data in light of model predictions, explaining whether reservoir behavior remains within expected bounds.

2. Any anomalies, including unexpected pressure changes, deviations in plume behavior, or irregularities in well integrity, must be reported promptly and analyzed thoroughly. If corrective actions are taken, the report must document their rationale and implementation. Operational reporting ensures that the PCS Secretariat and VVBs have continuous visibility into the project’s performance and that any emerging risks are identified early.

10.4 Monitoring Reports and Model Updates

1. Monitoring results play a critical role in evaluating whether CO₂ is behaving as predicted and whether the storage site remains stable. The developer must compile Monitoring Reports at intervals defined under PCS MRV rules. These reports must present monitoring data for the reservoir, caprock, groundwater systems, and any surface monitoring activities.

2. Monitoring Reports must go beyond raw data presentation. They must interpret results, explain trends, assess geochemical or geophysical changes, and relate observations to the expected plume trajectory, pressure evolution, and trapping mechanisms. Updated reservoir models must also be included when monitoring data suggest the need for recalibration. These updates help reduce uncertainty, refine predictions, and guide ongoing monitoring strategies.

10.5 Reporting of Anomalies and Corrective Actions

1. If any deviation from expected reservoir or monitoring behavior is observed, the developer must document it in a dedicated section of the Monitoring Report or through immediate notification pathways established under PCS governance. This includes unexpected increases in reservoir pressure, unusual seismic signals, unanticipated plume migration, groundwater chemistry changes, or surface-level indicators of gas movement.

2. Documentation must describe the nature of the anomaly, the methods used for investigation, the conclusions drawn from diagnostic assessments, and any corrective measures undertaken. Reports must clearly indicate whether the anomaly affects the validity of prior carbon unit issuance or necessitates updates to injection plans, modeling assumptions, or risk mitigation strategies.

10.6 Closure Documentation and Verification Materials

1. When injection ceases, the developer must produce a comprehensive Closure Plan and, at the end of the post-injection monitoring period, a Closure Verification Report. These documents must demonstrate that plume stabilization and pressure decline have occurred, that no leakage has been detected, and that reservoir behavior aligns with updated models.

2. Final closure documentation must include long-term monitoring data, well abandonment reports, updated geological and reservoir models, environmental monitoring results, and a clear justification that all PCS criteria for closure and permanence have been met. This documentation is essential for obtaining closure approval and transitioning to long-term stewardship or liability termination.

10.7 Data Retention and Archiving Requirements

1. CO₂ storage projects span long time horizons. To ensure continuity of oversight, all data generated throughout the project lifecycle must be securely retained. Data must be archived in formats that ensure accessibility, interpretability, and longevity. This includes raw measurement data, calibrated data, processed monitoring results, seismic surveys, well logs, model files, analysis reports, and correspondence related to compliance or corrective measures.

2. Records must be stored in secure systems with appropriate backup protocols. Metadata describing how data were collected, the instruments used, calibration details, and analytical methods must accompany all archived datasets. The developer must retain data for the full duration of project operations, closure, and post-closure stewardship, unless PCS explicitly approves a shorter retention period.

10.8 Transparency and Accessibility of Documentation

1. Transparency strengthens confidence in geological storage and enables independent validation. PCS requires that essential documents—including the PDD, Monitoring Reports, Validation and Verification reports, Closure Plans, and Closure Verification Reports—be made available to relevant authorities and stakeholders through designated platforms. Sensitive technical data may be protected where justified, but transparency must remain the default standard.

2. Clear communication of risks, performance metrics, monitoring outcomes, and corrective actions also enhances community trust and aligns the project with PCS safeguards.

10.9 Role of Documentation in Long-Term Stewardship

1. Long-term stewardship relies on the ability of future custodians to understand the geologic system, the history of injection, the monitoring strategies used, and the interventions applied. Thorough documentation ensures that future reviewers can reconstruct the evolution of the storage site even after operational personnel have changed. It provides assurance that the formation is stable and that the scientific evidence supporting permanence is robust.

2. As the project approaches the end of the post-injection monitoring period, documentation becomes the central tool used to justify transfer or termination of stewardship obligations. Without complete and reliable records, the project cannot meet PCS conditions for long-term closure.

Annex A - Key Geological, Petrophysical, And Geo-Mechanical Parameters

A.1 Overview

1. Annex A provides a consolidated reference for the parameters that govern CO₂ storage performance. These values and definitions underpin site characterization (Chapter 3), reservoir modeling (Chapter 4), and monitoring (Chapter 6). They also guide VVB assessments and ensure that all PCS CCS projects evaluate subsurface conditions consistently.

2. The parameters included in this annex represent the most influential controls on injectivity, plume migration, trapping efficiency, vertical containment, geo-mechanical stability, and long-term storage integrity.

A.2 Geological and Reservoir Parameters

1. The following table presents the essential geological parameters required for evaluating reservoir quality and caprock integrity.

Table A-1 — Geological Parameters and Interpretation Guidance

Parameter	Definition	Measurement Method	Typical Ranges / Notes	Relevance to CO₂ Storage
Reservoir Depth	Vertical depth of the primary storage interval below surface.	Wireline logs, seismic interpretation.	Usually >800 m for supercritical CO₂. Shallower depths require justification.	Determines CO₂ phase behavior, pressure conditions, and containment reliability.
Net Reservoir Thickness	Cumulative thickness of permeable, CO₂-storage-capable layers.	Well logs, core data, seismic.	Highly variable; >20 m commonly suitable.	Controls storage volume, plume geometry, and pressure distribution.
Lithology	Rock type and composition of reservoir and seal formations.	Core analysis, cuttings, petrography.	Sandstones, carbonates, basalts, and coal seams considered site-specific.	Governs porosity, permeability, reactivity, and caprock sealing.
Reservoir Continuity	Lateral and vertical extent of reservoir connectivity.	Seismic mapping, well correlations.	Continuous reservoirs preferred; compartmentalization increases complexity.	Influences injectivity, plume migration, and pressure dissipation.
Caprock Thickness	Total thickness of primary sealing formations.	Seismic, well logs, core samples.	Tens to hundreds of meters; thicker seals enhance containment.	Determines ability to retain buoyant CO₂ and resist pressure increases.
Caprock Mineralogy	Mineral composition affecting geochemical stability.	XRD, SEM, chemical analysis.	Clay-rich shales preferred; reactive minerals require assessment.	Influences caprock resistance to CO₂ exposure and long-term seal integrity.

257. Explanatory Note:

These parameters form the foundation of geological characterization. Together they determine whether the reservoir can receive CO₂ at required injection rates, whether the sealing system is robust, and how the plume will behave over time. Every parameter must be supported by measured data rather than assumption.

A.3 Petrophysical Parameters

1. Petrophysical parameters govern how CO₂ occupies pore space and how easily it migrates.

Table A-2 — Petrophysical Parameters and Interpretation Guidance

Parameter	Definition	Measurement Method	Typical Ranges / Notes	Importance
Porosity (Φ)	Fraction of rock volume that is pore space.	Core plug tests, NMR, density-neutron logs.	10–30% typical for saline aquifers; lower values reduce capacity.	Determines storage volume and influences flow.
Permeability (k)	Ability of rock to transmit fluids.	Core tests, well tests, pressure transient analysis.	10–1000 mD common; <10 mD may require multi-well injection.	Controls injectivity and plume migration.
Permeability Anisotropy	Ratio of horizontal to vertical permeability.	Core testing, geostatistical modeling.	kv often 1/10 to 1/100 of kh.	Controls plume shape and vertical migration.
Capillary Entry Pressure	Pressure required for CO₂ to enter caprock pores.	Mercury injection tests, core testing.	Higher values offer better sealing strength.	Primary determinant of caprock containment.
Residual CO₂ Saturation	Fraction of CO₂ trapped immobile after plume passes.	Laboratory core flooding, modeling.	Typically 10–30%.	Governs residual trapping, a key permanence mechanism.
Relative Permeability Curves	Relationship between CO₂ and brine flow at varying saturations.	Laboratory tests, history-matching.	Must be site-specific; published curves insufficient.	Essential for accurate modeling of migration and trapping.

259. Explanatory Note:

Petrophysical parameters interact strongly. High porosity with low permeability may limit injectivity, while high permeability increases plume mobility and potential migration. Capillary and relative permeability data are indispensable for predicting trapping efficiency and assessing leakage risk.

A.4 Geo-mechanical Parameters

1. Geo-mechanical conditions determine whether injection pressures can be sustained safely and whether faults or fractures may reactivate.

Table A-3 — Geo-mechanical Parameters and Interpretation Guidance

Parameter	Definition	Measurement	Typical Values	Importance
In-situ Stress State (σH, σh, σv)	Magnitudes of the three principal stresses.	Well logs, image logs, leak-off tests.	Varies regionally; ordering of stresses critical.	Determines safe injection pressure and fault stability.
Fracture Gradient	Pressure at which caprock or reservoir rock fractures.	Leak-off tests, minifrac tests.	Must exceed planned injection pressures.	Sets hard upper boundary for injection design.
Rock Strength (compressive, tensile)	Mechanical strength of reservoir and caprock.	Laboratory triaxial testing.	Site-specific; shale usually stronger in compression.	Influences resistance to deformation and failure.
Elastic Moduli (Young’s modulus, Poisson’s ratio)	Elastic behavior under stress.	Lab tests, well logs.	Varies by lithology.	Required for stress modeling and compaction prediction.
Fault Slip Tendency	Likelihood of fault reactivation under pressure increase.	Geo-mechanical simulation, friction coefficient estimation.	Depends on stress orientation and fault geometry.	Determines induced seismicity and leakage potential.

261. Explanatory Note:

Even a geologically strong site can become unsafe if geo-mechanical parameters are poorly understood. Injection plans must always remain within geo-mechanical limits, and these parameters provide the quantitative basis for those limits.

A.5 Hydrological and Fluid Flow Parameters

1. Hydrological behavior determines pressure dissipation and plume migration.

Table A-4 — Hydrological Parameters and Interpretation Guidance

Parameter	Definition	Measurement Method	Notes
Formation Pressure	Initial reservoir pressure prior to injection.	Pressure transient analysis, wireline tests.	Determines CO₂ density, mobility, and injectivity.
Formation Water Composition	Salinity, mineral content, chemical reactivity.	Geochemical sampling and analysis.	Influences solubility trapping and mineral reactions.
Aquifer Connectivity	Degree to which reservoir communicates with adjacent formations.	Well interference tests, seismic, modeling.	Impacts pressure buildup and brine displacement.
Pressure Transmissivity	Rate at which pressure diffuses through the formation.	Well testing and modeling.	Low transmissivity increases pressure risk.
Brine Compressibility	Deformation of brine under pressure.	Laboratory tests.	Affects pressure buildup and model calibration.

263. Explanatory Note:

Hydrology is central to pressure management and is often a limiting factor in storage capacity. Understanding transmissivity and connectivity is critical for predicting safe injection rates.

A.6 CO₂ Fluid Properties and Thermodynamic Parameters

1. These parameters control injection behavior and plume dynamics.

Table A-5 — CO₂ Fluid Properties

Parameter	Definition	Notes
CO₂ Density	Varies with pressure and temperature; key to mass calculations.	Supercritical density typically 400–800 kg/m³ at reservoir conditions.
CO₂ Viscosity	Affects injectivity and flow resistance.	Lower viscosity than brine → buoyant, mobile plume.
CO₂ Compressibility	Influences pressure response.	Must be included in dynamic simulation.
CO₂ Solubility in Brine	Governs solubility trapping.	Depends on salinity, pressure, and temperature.
Impurities in CO₂ Stream	SO₂, NOx, O₂, H₂S, water.	Affect corrosion, reactivity, phase behavior, and monitoring.

265. Explanatory Note:

Accurate thermodynamic modeling requires site-specific temperature and pressure conditions. Generic assumptions are not acceptable for PCS projects.

A.7 Monitoring Parameters (Reservoir, Groundwater, Surface)

1. These parameters are foundational to Chapter 6 monitoring requirements.

Table A-6 — Key Monitoring Parameters

Monitoring Parameter	Measurement	Purpose
Reservoir Pressure	Downhole sensors	Detect pressure buildup, confirm model accuracy, monitor geo-mechanical safety.
Temperature	Downhole sensors	Track thermal behavior, detect unusual flow.
CO₂ Saturation	Seismic, logging, modeling	Observe plume movement and trapping.
Groundwater Chemistry	Sample analysis	Detect brine displacement or leakage.
Microseismicity	Geophone arrays	Monitor fault activity or induced seismicity.
Soil Gas CO₂	Flux chambers, probes	Detect near-surface leakage where relevant.

A.8 Guidance on Parameter Uncertainty

1. Every parameter carries uncertainty, which must be quantified rather than ignored. Uncertainty affects model reliability, risk assessment, monitoring design, and injection planning. Developers must characterize uncertainty using sensitivity analysis, statistical modeling, scenario testing, or geological uncertainty workflows such as multiple realizations.

2. PCS requires that uncertainty not only be quantified but also reflected in conservative operational decisions. No parameter may be assumed precise without supporting data.

Annex B - Monitoring Techniques, Interpretation Methods, And Data Requirements

B.1 Overview of Monitoring Systems

1. Monitoring in geological CO₂ storage is a multi-layered activity that integrates subsurface, near-surface, and environmental measurements to ensure that injected CO₂ remains contained and behaves as predicted. No single monitoring method is sufficient; rather, a coordinated system of geophysical, geochemical, and engineering measurements provides the evidence needed to demonstrate containment, track plume evolution, and confirm the continued integrity of wells and geological seals.

2. Monitoring techniques must be selected based on site-specific geological characteristics, risk profiles, and the nature of the identified leakage pathways. Each method must be capable of producing data that are interpretable, traceable, and relevant to the monitoring objectives established in Chapter 6.

B.2 Downhole and Reservoir Monitoring Techniques

B.2.1 Pressure and Temperature Measurements

1. Reservoir pressure and temperature monitoring forms the core of subsurface surveillance. Continuous downhole gauges measure changes in pressure that reflect plume movement, injectivity conditions, and geo-mechanical responses. Temperature changes may indicate fluid movement or thermal mismatches between injected CO₂ and formation fluids. These measurements provide immediate indications of whether reservoir behavior aligns with modeled projections. Data must be collected at high frequency and stored in a manner that preserves temporal resolution. Interpretation requires comparison with simulation predictions and may reveal early deviation from expected performance.

B.2.2 Saturation Logging Tools

1. Pulsed neutron logging, dielectric logging, or resistivity-based tools can quantify CO₂ saturation in monitoring wells. These technologies detect changes in fluid composition and allow identification of the CO₂ front as it passes through logged intervals. Proper calibration is essential because variations in formation water salinity and rock composition can influence log response. Saturation logs contribute directly to plume tracking and history matching during reservoir model updates.

B.2.3 Fiber-Optic Distributed Sensing

1. Distributed Temperature Sensing (DTS) and Distributed Acoustic Sensing (DAS) provide continuous measurements along the entire length of a wellbore. DTS reveals temperature anomalies associated with fluid movement, while DAS can detect microseismic activity or flow-related acoustic signatures. These methods provide high-resolution data that complement conventional gauge-based monitoring and enable the detection of subtle anomalies that may precede larger issues.

B.3 Geophysical Monitoring Techniques

1. Geophysical techniques provide spatial and volumetric insights into plume evolution and reservoir behavior that cannot be obtained through wells alone.

B.3.1 4D Seismic Imaging

1. Time-lapse seismic, also known as 4D seismic, is one of the most powerful methods for mapping CO₂ plume geometry and reservoir changes over time. Repeated seismic surveys reveal changes in acoustic impedance associated with CO₂ saturation, pressure variations, and fluid substitution. Interpretation requires advanced processing techniques to isolate signal differences caused by CO₂ rather than acquisition noise or non-reservoir effects. The technique is particularly effective in reservoirs with significant seismic sensitivity and can resolve plume shape, vertical migration, and trapping trends. The frequency of surveys depends on plume dynamics, operational conditions, and cost considerations.

B.3.2 Crosswell Seismic and Vertical Seismic Profiling

1. Crosswell seismic provides high-resolution imaging between wells and is useful in monitoring plume movement near injection points. Vertical Seismic Profiling (VSP) enhances seismic resolution around the borehole and supports interpretation of 4D seismic data. These methods are appropriate for reservoirs where 3D seismic alone cannot resolve key stratigraphic or structural features that influence plume migration.

B.3.3 Electromagnetic and Resistivity Monitoring

1. CO₂ alters the electrical resistivity of reservoir fluids, making electromagnetic techniques valuable for plume detection. Controlled-source electromagnetic (CSEM) surveys or time-lapse resistivity logging can identify zones where resistivity changes occur due to CO₂ saturation. These methods are particularly useful in formations where seismic sensitivity is low, such as basalt or certain carbonate reservoirs. Interpretation must account for temperature, salinity, and lithology effects that can influence resistivity signals.

B.3.4 Gravity and Microgravity Surveys

1. Changes in reservoir density due to CO₂ saturation or brine displacement produce small but measurable variations in gravitational fields. Gravity and microgravity surveys can detect these density differences and help estimate volumetric changes. Although the technique has lower spatial resolution than seismic methods, it provides complementary data that support mass-balance evaluations and long-term stabilization assessments.

B.3.5 Ground Deformation Monitoring (InSAR and GPS)

1. Surface deformation monitoring detects uplift or subsidence caused by reservoir pressure changes. Interferometric Synthetic Aperture Radar (InSAR) provides wide-area, high-precision deformation measurements, while GPS stations offer continuous point measurements. These techniques help identify anomalies in pressure evolution or unexpected subsurface behavior that could indicate geo-mechanical stress or leakage risk. Interpretation requires careful separation of natural ground movement from injection-related effects.

B.4 Geochemical and Environmental Monitoring Techniques

B.4.1 Groundwater Sampling and Chemical Analysis

1. Groundwater monitoring detects any migration of CO₂ or displaced brine into potable or protected aquifers. Geochemical indicators include dissolved inorganic carbon, pH, alkalinity, electrical conductivity, and the presence of tracer compounds if used. Sampling must follow strict protocols to avoid contamination, and results must be compared against baseline values established prior to injection. Sustained deviations may indicate leakage or pressure-driven brine movement.

B.4.2 Soil Gas and Near-Surface CO₂ Flux Measurements

1. In areas with potential surface leakage pathways, soil gas sensors or flux chambers may be deployed. These instruments detect changes in soil CO₂ concentration or flux that deviate from natural background patterns. Measurements must account for natural variability due to temperature, moisture, and biological activity. Surface monitoring is generally required only when risk assessments indicate plausible leakage pathways near the ground surface.

B.4.3 Isotope and Tracer Monitoring

1. Stable carbon isotopes or introduced tracers can distinguish injected CO₂ from natural background sources. This technique strengthens the interpretation of groundwater, soil gas, and atmospheric monitoring results. Isotopic monitoring is especially valuable when natural CO₂ levels fluctuate seasonally or when biological processes complicate interpretation.

B.5 Micro-seismic and Seismicity Monitoring

1. Micro-seismic detection involves measuring very small seismic events that occur due to stress changes associated with injection. These signals provide insights into the geo-mechanical behavior of faults and fractures. A micro-seismic network can reveal whether injection-induced stresses are influencing fault stability. Seismometers must be placed to capture events within the reservoir and caprock. Interpretation requires distinguishing between natural tectonic events and injection-related occurrences. Any increase in seismic activity must be evaluated within the geo-mechanical context of the site to determine operational implications.

B.6 Well Integrity Monitoring Techniques

1. Well integrity monitoring ensures that injection and observation wells remain secure and free from leakage pathways.

B.6.1 Cement Bond Logs and Ultrasonic Imaging

1. Cement evaluation tools examine the quality of cement bonding along the casing. Poor bonds, microannuli, or channels may act as leakage pathways and must be investigated. Ultrasonic tools provide high-resolution images of cement integrity and can detect subtle defects that conventional logs may miss.

B.6.2 Pressure and Annulus Monitoring

1. Monitoring the pressure in the annulus between casing strings can indicate communication between well sections. Unexpected pressure buildup or changes in annulus behavior may signal casing or cement integrity issues. Continuous monitoring is recommended in wells where CO₂ exposure is significant.

B.6.3 Mechanical Integrity Tests

1. Periodic mechanical integrity tests apply pressure to the well system to confirm that no leaks exist across well components. Results provide confidence that the well remains structurally sound and capable of supporting long-term injection and monitoring requirements.

B.7 Data Requirements and Interpretation Standards

1. The monitoring data must be collected in a manner that ensures accuracy, repeatability, and interpretability. All measurements must be time-stamped, calibrated, and accompanied by metadata describing the method of acquisition, instrument specifications, and any corrective factors applied. Data interpretation must be grounded in model predictions and supported by multiple lines of evidence whenever possible.

2. Reservoir monitoring data must be analyzed in conjunction with dynamic simulation outputs to confirm alignment between observed and modeled behavior. Geophysical data must be interpreted by qualified professionals using established processing workflows. Geochemical and environmental data must be compared against baseline conditions and evaluated within the broader hydrogeological context.

3. Monitoring interpretations must be conservative, particularly where uncertainty exists. PCS requires that developers demonstrate an evidence-based understanding of site behavior, supported by monitoring and modeling integration rather than assumptions.

B.8 Criteria for Monitoring Method Selection

1. The selection of monitoring techniques must reflect the site’s geological characteristics, risk profile, and monitoring objectives. Seismic methods may be central in clastic reservoirs with strong impedance contrasts, while electromagnetic techniques may be more effective in basalt formations or low-seismic-sensitivity environments. Groundwater monitoring is essential where potable aquifers exist above the storage complex. Microseismic monitoring is necessary where faults or stress-sensitive zones pose geo-mechanical risks.

2. Monitoring selections must be justified in the Monitoring Plan, which must clearly articulate why each method was chosen, how it contributes to risk management, and how it integrates with other monitoring datasets.

B.9 Data Integration for Model Updating and Performance Verification

1. Monitoring data must be used to update reservoir models and refine predictions of plume evolution, pressure distribution, and long-term stability. This integration allows the developer to detect discrepancies early and to respond appropriately. Updated models must reflect new geological insights and be validated against monitoring observations.

2. Performance verification depends on this integration. A project cannot rely solely on pre-injection models; it must demonstrate that models remain valid in light of observed data. The iterative process of model updating strengthens the reliability of predictions used to justify closure and long-term storage security.

Annex C - Standardized PCS Templates

C.1 Purpose of the Templates Annex

1. Annex C provides standardized templates for documenting the technical basis of a CO₂ storage project. These templates support the preparation of the Project Design Document (PDD), Monitoring Report, Risk Assessment, and Site Characterization Report. They ensure that essential information is presented clearly, consistently, and in a format that facilitates independent review.

2. Templates included in this annex serve as guidance structures rather than rigid forms. Projects may expand or adapt fields where necessary, but core elements must remain intact to comply with PCS.

C.2 Site Characterization Summary Template

1. This template provides a high-level synthesis of geological, petrophysical, geo-mechanical, and hydrological characteristics. It supports VVB validation by presenting key parameters in a structured, easily reviewable format.

Table C-1 — Site Characterization Summary

Category	Parameter	Summary Description	Data Source / Method	Key Values / Notes
Geological Framework	Depth of reservoir	Description of depth to top and base of reservoir.	Logs, seismic interpretation.	Depth range in meters.
	Reservoir lithology	Primary rock type and depositional environment.	Core, petrographic analysis.	Sandstone / carbonate etc.
	Caprock description	Thickness, lithology, sealing characteristics.	Logs, core, seismic.	Integrity assessment summary.
Petrophysical Properties	Porosity	Spatial distribution of porosity.	Core analysis, logs.	Average and range.
	Permeability	Horizontal and vertical permeability.	Core tests, well tests.	kh and kv values.
	Capillary entry pressure	Seal capacity measurement.	Laboratory testing.	Key thresholds.
Geomechanics	Stress regime	Description of σH, σh, σv.	Image logs, leak-off tests.	Ordering and magnitudes.
	Fracture gradient	Maximum safe injection pressure.	Minifrac tests.	psi / MPa values.
Hydrology	Formation pressure	Initial reservoir conditions.	Pressure transient tests.	psia / MPa.
	Connectivity	Lateral/vertical pressure communication.	Modeling, testing.	Qualitative and quantitative assessment.
Well Infrastructure	Existing wells	Count and condition.	Well records.	Identify legacy wells.
	Planned wells	Number and type.	Project design.	Injectors, monitors.

298. Narrative Use:

The template provides regulators and VVBs a concise but comprehensive overview of the subsurface system before detailed modeling or monitoring plans are assessed.

C.3 CO₂ Storage Risk Register Template

1. A risk register is a structured record of all identified risks, their likelihood, consequences, mitigation measures, and monitoring implications.

Table C-2 — PCS Geological Storage Risk Register

Risk Category	Description of Risk	Likelihood (Qualitative)	Consequence (Qualitative)	Supporting Evidence	Mitigation Measures	Monitoring Requirements
Geological	Unexpected heterogeneity affecting plume migration	Low / Medium / High	Low / Medium / High	Seismic and core data	Additional wells, updated model	Increased plume mapping frequency
Geo-mechanical	Pressure-induced fault reactivation	Medium	High	Geo-mechanical modeling	Pressure limits, brine extraction	Microseismic monitoring
Hydrological	Brine displacement into shallower aquifers	Low / Medium / High	Medium / High	Hydrogeology assessment	Pressure management	Groundwater sampling
Well Integrity	Leakage via legacy wells	Medium	High	Records, logs	Remediation or exclusion zones	Annulus and groundwater monitoring
Environmental	Soil or surface leakage	Very low	Medium	Risk assessment	Exclusion of sensitive areas	Soil flux measurements
Operational	Injectivity decline	Medium	Low–Medium	Well testing	Adjust injection profile	Injection pressure monitoring

300. Narrative Use:

This table becomes part of the Project Design Document and is updated throughout the project lifecycle as new monitoring data refine risk understanding.

C.4 Monitoring Matrix Template

1. The Monitoring Matrix links risks, monitoring objectives, techniques, frequency, and acceptance criteria in a structured decision-support format.

Table C-3 — PCS Monitoring Matrix

Monitoring Objective	Monitoring Parameter	Technique / Method	Spatial Coverage	Frequency	Acceptance Criteria	Trigger for Action
Confirm reservoir pressure behavior	Pressure in reservoir	Downhole sensors	Injection + monitoring wells	Continuous	Within modeled range	Pressure deviation beyond established bounds
Track CO₂ plume migration	CO₂ saturation / plume geometry	4D seismic, resistivity, saturation logs	Storage complex	Periodic (site-specific)	Alignment with model	Plume deviation in direction or extent
Detect potential leakage	Groundwater chemistry	Sampling + analysis	Shallow aquifers	Quarterly or risk-based	Within baseline variability	Chemical anomalies
Assess geo-mechanical stability	Micro-seismicity	Seismic array	Regional	Continuous	No significant induced events	Detection of upward trend or clustered events
Verify well integrity	Annulus pressure, cement bond	Logs and sensors	All wells	Annual or risk-based	Stable profiles	Increasing annulus pressure or bond deterioration
Near-surface assurance	Soil gas CO₂	Flux chambers / probes	Selected risk zones	Annual or as needed	Within natural ranges	Elevated CO₂ flux matching leakage signatures

302. Narrative Use:

This matrix ensures each monitoring activity has a clear purpose and threshold for interpretation. It supports consistency in reporting and VVB assessments.

C.5 Incident and Corrective Action Template

1. This template standardizes how deviations, anomalies, or incidents must be documented and reported.

Table C-4 — Incident and Corrective Action Record

Incident Description	Date Detected	Monitoring Method	Immediate Actions Taken	Root Cause Analysis	Corrective Action	Verification of Resolution
Describe observed anomaly	Timestamp	Data source	Operational response	Investigation summary	Remediation or mitigation	Evidence that issue is resolved

304. Narrative Use:

This table ensures traceability of every anomaly and supports regulatory compliance and VVB validation.

C.6 Template for Annual Geological Storage Performance Summary

1. This annual summary is required for transparent reporting to PCS and stakeholders.

Table C-5 — Annual Performance Summary

Category	Key Results	Interpretation	Alignment with Model	Required Adjustments
Injection performance	Injection rates, volumes, pressures	Operational interpretation	Yes/No with explanation	Adjustments if any
Reservoir behavior	Pressure, plume data	Analysis vs forecast	Deviations or confirmations	Model updates
Monitoring outcomes	Groundwater, seismic, well integrity	Interpretation	Alignment	Changes to monitoring
Risk profile updates	New risks or reevaluated risks	Explanation	How it affects project	Required mitigation

Annex D - Glossary & Scientific References

D.1 Purpose of the Glossary

1. This glossary consolidates all technical, geological, engineering, and regulatory terminology used throughout the PCS Geological Storage Technical Guidance. It ensures that all project developers, VVBs, regulators, and stakeholders use the terms consistently and interpret them in a scientifically accurate manner. These definitions draw upon established usage in CCS practice, including IPCC Special Reports, ISO standards, IEA guidelines, and leading national geological surveys.

D.2 Glossary of Terms

• Abandoned Well: A well that has been permanently taken out of service. In the context of CO₂ storage, abandoned wells may pose leakage risks if cement, casing, or plugging materials have degraded.

• Aquifer: A permeable geological formation capable of storing and transmitting groundwater. In CO₂ storage, shallow aquifers must be protected from brine displacement or CO₂ migration.

• Basalt Formation: A volcanic rock formation that may store CO₂ through mineralization. Basalts differ from sedimentary reservoirs in their geochemical behavior.

• Baseline Conditions: The environmental, chemical, and physical state of the reservoir, groundwater, and surface prior to CO₂ injection. Baseline conditions are used to detect changes during monitoring.

• Brine Displacement: The movement of saline formation water caused by CO₂ injection. Excess pressure can displace brine into overlying formations or aquifers.

• Capillary Entry Pressure: The minimum pressure required for CO₂ to enter rock pores, especially within caprock. Higher values indicate stronger sealing capacity.

• Caprock: A low-permeability geological layer overlying the reservoir that prevents upward migration of CO₂. Caprock integrity is essential for containment.

• Closure Verification Report: A formal document demonstrating that the storage site has stabilized, the plume has ceased significant migration, pressure has declined, and no leakage is occurring.

• CO₂ Plume: The three-dimensional distribution of injected CO₂ within the reservoir. Plume movement is controlled by buoyancy, viscosity, reservoir properties, and pressure gradients.

• Containment: The ability of the geological formation and engineered well systems to prevent CO₂ from escaping the designated storage complex.

• Depleted Oil or Gas Field: A hydrocarbon reservoir where hydrocarbons have been largely extracted. Such formations may be repurposed for CO₂ storage due to known geology and existing data.

• Distributed Acoustic Sensing (DAS): A fiber-optic technique that measures acoustic signals along the length of a well to detect seismic or flow-related activity.

• Distributed Temperature Sensing (DTS): A real-time fiber-optic method measuring temperature variations in a well, providing insights into fluid movement and well integrity.

• Dynamic Simulation: Numerical modeling that predicts CO₂ migration, pressure evolution, and trapping behavior over time.

• Elastic Moduli: Mechanical properties of rock describing its deformation under stress. These are essential for geo-mechanical modeling.

• Formation Pressure: The natural pressure of fluids in the reservoir prior to injection. Formation pressure influences CO₂ density, injectivity, and plume behavior.

• Fracture Gradient: The pressure at which rock fractures. Injection pressures must remain below this limit.

• Geo-mechanical Model: A model that predicts stresses, strains, and potential fault or fracture behavior during injection.

• Groundwater Monitoring: Sampling and chemical analysis conducted to detect CO₂ intrusion or brine displacement into shallow aquifers.

• Hydraulic Connectivity: The degree to which fluids or pressure changes can move between geological units.

• Induced Seismicity: Seismic events caused by fluid injection altering subsurface stresses.

• Injection Well: A well constructed for the purpose of injecting CO₂ into a geological formation.

• Leakage Pathway: A geological or engineered feature through which CO₂ or brine could migrate out of the storage complex.

• Legacy Well: A well drilled historically, often with inadequate records or outdated abandonment methods. Legacy wells pose elevated leakage risks.

• Mechanical Integrity Test (MIT): A test conducted to confirm that a well remains structurally sound and free of leaks.

• Mineral Trapping: The long-term immobilization of CO₂ through reaction with reservoir minerals to form stable carbonates.

• Monitoring Well: A well used to observe reservoir pressure, CO₂ saturation, fluid chemistry, or seismicity.

• Permanent Containment: The condition in which injected CO₂ remains immobilized or stored in a stable geological configuration indefinitely.

• Porosity: The proportion of pore space in rock, determining its ability to store CO₂.

• Pressure Dissipation: The reduction of reservoir pressure after injection ceases due to fluid redistribution and geological diffusion.

• Pressure Footprint: The spatial extent of pressure changes caused by injection, which is often larger than the CO₂ plume itself.

• Residual Trapping: The immobilization of CO₂ as disconnected droplets within pore spaces once the plume has migrated past.

• Reservoir Model: A digital model representing geological structure, rock properties, and flow behavior of the storage site.

• Seismic Monitoring: Use of seismic imaging or sensors to detect plume movement, reservoir changes, or seismic events.

• Solubility Trapping: The dissolution of CO₂ into formation water, reducing its mobility.

• Static Geological Model: A three-dimensional representation of lithology, structure, and property distribution, serving as the basis for dynamic models.

• Storage Complex: The reservoir, caprock, and any secondary sealing units that collectively provide containment.

• Supercritical CO₂: CO₂ in a dense phase above its critical temperature and pressure, allowing efficient storage.

• Trapping Mechanism: Any process that immobilizes or contains CO₂, including structural, residual, solubility, or mineral trapping.

• Well Integrity: The capacity of a well to prevent uncontrolled fluid movement within or outside the wellbore.

D.3 Scientific References

1. This section provides the foundational scientific literature, standards, and guidance documents that inform PCS requirements. The list is selective and represents authoritative sources used globally in CCS regulation and practice.

• IPCC Special Report on Carbon Dioxide Capture and Storage (2005)

• IPCC 2006 Guidelines + 2019 Refinement

• ISO 27914:2017 - Carbon Dioxide Capture, Transportation and Geological Storage - Geological Storage

• ISO 27916:2019 - Carbon Dioxide Capture, Transportation and Geological Storage - Quantification and Verification

• United States EPA Underground Injection Control (UIC) Program - Class VI Wells

• European Union CCS Directive (2009/31/EC)

• IEA Greenhouse Gas R&D Programme (IEAGHG) Technical Reports

• CSLF (Carbon Sequestration Leadership Forum) Best Practice Manuals

• National geological surveys (e.g., USGS, BGS, GSC)

• Industry reference texts and peer-reviewed literature in CCS-relevant journals