AER Directive 065 — CO₂ Storage Scheme Application Template
Complete application structure for a Class III/IV CO₂ storage scheme under AER Directive 065 (Requirements for Acid Gas Injection and CO₂ Storage Schemes). Each section maps to D065 requirements with guidance on what the AER expects. Expand each section for detailed data requirements and pro tips.
1 General Information & Scheme Description
Applicant Information
Legal name, AER licensee code (BA code), contact person, mailing address, phone, email. Must match AER's licensee records exactly.
Scheme Description & Purpose
Type of scheme (CO₂ storage), source of CO₂ (capture facility, pipeline), purpose (permanent geological storage for emissions reduction credits). State whether this is a new scheme or amendment to existing.
Location
Legal Subdivision (LSD), Section, Township, Range, Meridian. NAD83 coordinates for all well locations. Surface and bottom-hole locations if deviated wells.
Target Formation(s)
Name of injection zone(s), depth interval (mKB/mTVD), formation top/base. If stacked storage, list all target intervals.
CO₂ Stream Composition
Full compositional analysis of the injected CO₂ stream. Include impurities (H₂S, N₂, CH₄, H₂O, SOₓ, NOₓ). State capture technology and expected variability.
Project Timeline
Proposed start date, injection duration (years), total injection volume, post-injection monitoring period, anticipated closure date. Include ramp-up schedule if phased.
Carbon Sequestration Tenure Agreement (CSTA)
Evidence of current CSTA from the Alberta Crown. Must validate pore space rights for all proposed well locations. Tenure must be maintained continuously — AER verifies at time of application.
2 Geological Assessment
Regional Geological Setting
Sedimentary basin context (WCSB), structural province, depositional environment. Include regional cross-sections and stratigraphic column from Precambrian basement to surface.
Stratigraphy — Injection Zone
Formation name, age, lithology, depositional environment, thickness (gross/net), lateral extent. Provide well-log correlation panels across the AoR. Include type logs with key formation tops.
Stratigraphy — Primary Caprock/Seal
Formation name, lithology, thickness, lateral continuity, capillary entry pressure, breakthrough pressure. Demonstrate seal integrity via mercury injection capillary pressure (MICP) data or analogues.
Secondary Seals & Containment
Identify additional confining units above primary seal. Multi-barrier containment concept. Discuss aquitards and their hydraulic properties.
Structural Geology
Faults (location, throw, orientation, sealing capacity), fracture systems, structural closures. Include structure maps (top of injection zone) from 3D seismic if available. Assess fault reactivation potential (Mohr-Coulomb, slip tendency).
Hydrogeological Assessment
Baseline groundwater conditions, shallow aquifer identification (base of groundwater protection), regional flow regime, TDS profiles. Demonstrate isolation between injection zone and BGWP.
Geomechanical Assessment
In-situ stress state (σH, σh, σv), pore pressure gradient, fracture gradient. Maximum allowable injection pressure (typically 90% of fracture pressure). Include Mohr circle analysis and stress path during injection.
3 Reservoir Characterization & Modelling
Reservoir Properties
Porosity (core, log-derived), permeability (core, DST, well test), net pay, net-to-gross ratio. Include histograms and spatial distributions. Report geometric vs. arithmetic mean permeability and discuss anisotropy (kv/kh).
Formation Fluid Properties
Initial pressure and temperature, pressure gradient, formation water salinity/TDS, water chemistry (major ions). CO₂ properties at reservoir conditions (density, viscosity, solubility in brine). PVT data or EOS model parameters.
Multiphase Flow Properties
Relative permeability curves (drainage and imbibition for CO₂-brine system), capillary pressure curves, residual CO₂ saturation. Source: core floods on native rock or justified analogues.
Numerical Simulation Model
Simulator used (CMG-GEM, ECLIPSE-CO2STORE, TOUGH2, etc.), grid dimensions and resolution, boundary conditions, well model. Describe upscaling from geological model to simulation grid. Include sensitivity analysis on key parameters.
Storage Capacity Estimate
Static volumetric estimate (Meff = A × h × φ × ρCO₂ × E), dynamic simulation-based estimate, storage efficiency factors used. Report P10/P50/P90 range. Compare analytical and numerical results.
CO₂ Trapping Mechanisms
Quantify contribution of: structural/stratigraphic trapping, residual (capillary) trapping, solubility trapping, mineral trapping. Time evolution of trapping mechanisms over injection and post-injection periods.
Thermal Fracturing Assessment
Preliminary thermal-mechanical analysis of cold CO₂ injection into warm formation. Assess thermal stress near wellbore, potential for thermally-induced fracturing, and implications for caprock integrity. AER now requires a revised geomechanical modelling report within 2 years of injection start.
4 Area of Review (AoR) & Well Integrity
AoR Delineation
Methodology used (pressure-based, plume-based, or combined). Define the AoR as the greater of: (1) modelled CO₂ plume extent + buffer, or (2) area where pressure increase exceeds threshold. Include maps at end of injection and end of PISC.
Existing Well Inventory
Complete inventory of ALL wells penetrating the injection zone and caprock within the AoR. For each well: UWI, status (active/suspended/abandoned), total depth, completion interval, casing/cement details, current licensee.
Well Integrity Assessment
For each well in the AoR: review original completion reports, cement bond logs (CBL/VDL), casing inspection logs, pressure test records. Classify integrity risk (high/medium/low). Identify wells penetrating the seal that lack adequate cement across the caprock.
Corrective Action Plan
For each well identified as high or medium risk: proposed remediation (squeeze cementing, casing repair, re-abandonment). Timeline and responsibility. Demonstrate that all wells will have adequate barrier integrity before injection commences.
Legacy Well Assessment
For pre-1950s wells where records may be incomplete: describe approach to verifying abandonment adequacy. Consider ERCB Bulletin 2012-02 and current AER requirements for CO₂-resistant cement.
Hydraulic Fracturing Risk from Offset Operations
Assess risk of loss of hydraulic isolation in the target zone due to hydraulic fracturing treatments in overlying/underlying formations within the AOI. If unconventional development (Duvernay, Montney, etc.) is active nearby, evaluate whether frac jobs have compromised the seal or created communication pathways.
5 Injection Well Design & Operations
Well Construction
Casing program (surface, intermediate, production casing — grades, weights, connections), cement program (volumes, CO₂-resistant cement type, planned TOC), wellbore schematic. All materials must be CO₂-compatible (13Cr or higher for tubing, CO₂-resistant elastomers).
Injection Parameters
Maximum injection rate (t/d), maximum surface injection pressure, maximum bottomhole injection pressure (must not exceed 90% fracture pressure), injection temperature range. Include injectivity analysis from well tests or simulation.
Wellhead & Surface Facilities
Wellhead pressure/temperature ratings, metering equipment (flow, pressure, temperature), safety shutdown systems, corrosion monitoring. SCADA integration for real-time data transmission to AER.
Annular Monitoring
Annular pressure monitoring program, leak detection thresholds, response procedures for sustained casing pressure (SCP). AER expects continuous annular pressure monitoring on all injection wells.
Operational Procedures
Start-up, normal operations, shut-in, and emergency procedures. CO₂ phase management (avoid two-phase flow in wellbore). Thermal stress analysis for cold CO₂ injection into warm formations.
6 Risk Assessment
FEP (Features, Events, Processes) Analysis
Systematic identification of all relevant FEPs using an established framework (e.g., Quintessa CO₂ FEP database). Categorize by: assessment basis (geological, operational, external), likelihood, consequence. Document screening rationale for excluded FEPs.
Risk Register
Comprehensive risk register with: risk ID, description, category (containment, conformance, operational, HSE), likelihood (1-5), consequence (1-5), risk ranking, mitigation measures, residual risk. Use bow-tie diagrams for top risks.
Leakage Pathway Assessment
Evaluate all potential leakage pathways: (1) through caprock (diffusion, fractures), (2) via wells (existing and injection), (3) along faults, (4) lateral migration beyond AoR. Quantify leakage rates for credible scenarios.
Induced Seismicity Assessment
Baseline seismicity, proximity to known faults, assessment of injection-induced seismicity potential. Include traffic light protocol (TLP) with magnitude thresholds and operational responses. Reference AER Subsurface Order No. 2.
Quantitative Risk Assessment (if applicable)
Monte Carlo analysis for key uncertainties, probabilistic containment assessment, sensitivity analysis. Required for large-volume schemes (>1 Mt/yr).
7 Measurement, Monitoring & Verification (MMV)
MMV Plan Overview
Describe the overall monitoring philosophy: risk-based, phased, adaptive. MMV must address containment assurance (CO₂ stays in target zone), conformance verification (plume matches predictions), and quantification (volumes stored).
Baseline Monitoring
Pre-injection baseline surveys: groundwater sampling, soil gas surveys, seismic (if applicable), pressure monitoring. Minimum 12 months of baseline data before injection. Define baseline statistical ranges for anomaly detection.
Operational Monitoring
During injection: continuous wellhead P/T/Q, periodic downhole gauges, formation pressure monitoring (observation wells), time-lapse seismic (frequency depends on volume), groundwater monitoring, soil gas monitoring. Reporting frequency to AER.
Above-Zone Monitoring
Monitoring of formations above the primary seal: pressure, fluid composition. Purpose: early detection of any CO₂ migration through the seal. May use dedicated monitoring wells or intermediate-zone completions.
Post-Injection Monitoring
Continued monitoring after cessation of injection. Minimum duration and scope as required by AER (typically aligned with pressure stabilization and plume stability). Define criteria for monitoring frequency reduction.
Data Management & Reporting
Data acquisition, storage, QA/QC, and reporting protocols. Annual MMV reports to AER. Digital data submission requirements (Petrinex, DDS).
Hall Plot Analysis Program
Plan for Hall plots of constant average reservoir pressure to detect unexplained anomalous injection rates and pressure data that could indicate fracturing. This is a required component of annual reporting.
Vegetation Health & Surface Leak Monitoring
Technologies for monitoring changes in vegetation health that could indicate surface CO₂ leaks. Include remote sensing, InSAR for surface deformation, and near-surface soil gas monitoring network design.
Downhole Microseismic Arrays
Assessment of need for downhole microseismic arrays in deep monitoring wells for induced seismicity detection. Surface arrays may be insufficient for detecting low-magnitude events at depth.
8 Public Consultation & Stakeholder Engagement
Participant Involvement Program
Identify all persons who may be directly and adversely affected. Minimum notification radius per AER Directive 056. Document consultation efforts: letters, meetings, open houses. Record concerns raised and how they were addressed.
Indigenous Consultation
Crown consultation obligations for First Nations and Métis communities with traditional territory in the project area. Document engagement with relevant Treaty organizations and Métis Nation of Alberta.
Objection Resolution
If objections are filed, document ADR (Appropriate Dispute Resolution) efforts. If unresolved, the application may be referred to an AER hearing. Prepare for regulatory hearing process.
9 Emergency Response Plan (ERP)
Emergency Planning Zone (EPZ)
Calculate EPZ per AER Directive 071. For CO₂ storage, consider H₂S content (if any) in the stream. If pure CO₂, EPZ may be based on CO₂ release dispersion modelling. Include worst-case release scenario.
Response Procedures
Detection → Assessment → Notification → Response → Remediation. Specific procedures for: wellhead leak, subsurface containment loss, pipeline rupture (if applicable). Include decision trees and roles/responsibilities.
Notification Requirements
AER emergency line, local authorities, affected residents, Alberta Environment. Notification timelines per D071. Include contact lists and communication protocols.
Training & Drills
Annual ERP exercises, community notification drills, tabletop exercises for containment loss scenarios. Document training records and exercise outcomes.
10 Financial Assurance & Liability
Closure Cost Estimate
Detailed cost estimate for: well abandonment (all wells), facility decommissioning, surface reclamation, post-closure monitoring. Use current AER cost benchmarks. Include contingency (typically 15-25%).
Financial Security Instrument
Form of security (letter of credit, surety bond, AER-approved alternatives). Amount must cover full closure cost estimate. Security must be in place before injection commences.
Long-Term Liability Transfer
Post-closure liability transfer to the Crown under the Carbon Sequestration Tenure Regulation. Criteria: demonstrate containment, plume stability, pressure dissipation, no material risk. Typical minimum post-injection period: 10-20 years.
11 Closure & Post-Injection Site Care (PISC)
Well Abandonment Plan
Abandonment procedures for all injection and monitoring wells per AER Directive 020. CO₂-resistant cement requirements. Abandonment pressure testing criteria. Sequence and timeline.
PISC Monitoring Program
Reduced-intensity monitoring program post-injection. Define: what is monitored, frequency, success criteria for demonstrating containment and stability. Adaptive management — reduce monitoring as confidence in containment grows.
Closure Criteria
Measurable criteria for site closure and liability transfer: (1) pressure stabilization, (2) plume extent matches or is within predictions, (3) no evidence of containment loss, (4) all wells properly abandoned, (5) surface reclamation complete.
12 Environmental Assessment
Environmental Impact Assessment
Surface disturbance (well pads, access roads, pipelines), wildlife and vegetation, wetlands, historical resources. May require EPEA approval from Alberta Environment depending on project scale. Federal Impact Assessment Act may apply for cross-provincial projects.
Greenhouse Gas Accounting
Net GHG balance: CO₂ stored minus emissions from capture, compression, transportation, injection operations. Life-cycle analysis. Quantification protocol for Alberta TIER/federal OBPS credits.
D065 Compliance Checklist — CO₂ Storage Scheme
Track your application completeness. Check items as you prepare each component. Progress is maintained during your session.
Step-by-Step D065 Submission Guide
The AER D065 submission process from pre-application to approval. Typical timeline: 6-18 months depending on complexity, consultation outcomes, and completeness of the application.
Pre-Application Meeting with AER
Request a pre-application meeting with the AER's CCS team. Present the project concept, target formation, and high-level technical approach. This is not mandatory but strongly recommended — it reveals what the AER will focus on and can prevent months of deficiency responses.
Public Consultation (Directive 056)
Initiate participant involvement per AER Directive 056. Send notification letters to all landowners, residents, and occupants within the prescribed distance. Hold information sessions for the local community. Document all interactions meticulously — the AER will review your consultation record.
Prepare Technical Application Package
Compile all 12 sections of the D065 application using the template in this tool. Key workstreams typically running in parallel:
- Geological characterization and reservoir modelling (longest lead time)
- AoR delineation and existing well inventory
- Risk assessment and MMV plan
- Well design and facilities engineering
- ERP and closure plan
- Financial assurance arrangements
Internal QA/QC Review
Before submission, conduct a thorough internal review:
- Cross-reference all data between sections (depths, coordinates, formation names must be consistent)
- Verify all maps are properly geo-referenced and at appropriate scale
- Ensure simulation model inputs match geological description
- Confirm AoR encompasses all scenarios (not just base case)
- Verify financial security amount covers updated closure cost estimate
Submit via AER OneStop
Submit the complete application package through AER's OneStop online system. Include the cover letter (use the sample cover letter template from Downloads), all technical appendices, and consultation record. Pay applicable fees.
- Application must be signed by authorized company representative
- All well licence applications (if needed) can be bundled
- Digital data submissions per AER data requirements
- Retain submission confirmation number
Completeness Review
AER conducts an initial completeness check. They verify all required sections are present and all data files are accessible. This is NOT a technical review — it only confirms the application package is complete. If deficiencies found, you'll receive a completeness deficiency letter.
Technical Review & Information Requests
AER's technical reviewers (geologists, engineers, environmental scientists) conduct detailed assessment. Expect Supplemental Information Requests (SIRs). Common SIR topics:
- Additional sensitivity runs or uncertainty scenarios in simulation
- Clarification on fault seal analysis or caprock integrity
- More detail on MMV technology selection and detection limits
- Updated AoR based on revised simulation results
- Well integrity details for specific offset wells
Hearing (if applicable)
If stakeholder objections remain unresolved, AER may schedule a regulatory hearing. The hearing panel will assess both technical merits and stakeholder concerns. Prepare expert witnesses and technical evidence packages.
Decision & Conditions
AER issues approval (with conditions) or denial. Approval conditions typically include: specific MMV requirements, reporting schedules, maximum injection parameters, financial security amount. The approval letter becomes your operational licence.
Phased Well Approvals (if applicable)
If your scheme includes undrilled wells, each requires a separate D065 application after drilling with: updated geological interpretation, bounding formation assessment, BHP/sandface/fracture pressures, PTA analysis, and CO₂ plume/pressure model re-runs. You have a 24-month hard deadline from scheme approval — AER will not grant extensions and may rescind approvals.
Pre-Injection Compliance
Before first injection, ALL gate conditions must be cleared: D051 and D071 confirmed by AER in writing, MMV plan commitments met, closure plan approved, seismic hazard assessment accepted. Additionally:
- Complete baseline monitoring (minimum 12 months)
- Verify CSTA is current and covers all well locations
- Confirm financial security is posted
- Prepare Petrinex well status codes (Fluid: CO2, Mode: N/A, Type: INJ, Structure: CARBON SEQU)
- Conduct pre-injection pressure test
- Notify AER of planned injection start date
Companion Calculators & Templates
Downloadable tools to support your D065 application. The AoR calculator provides analytical estimates — always validate with numerical simulation for the final submission.
AoR & Storage Capacity Calculator
Multi-method analytical calculator: Radial Buckley-Leverett plume radius, Theis-based pressure front radius, and USDOE volumetric storage capacity estimation. Includes comparison summary and input validation.
Sample Cover Letters
Pre-formatted cover letter templates for D065 CO₂ storage scheme application submission to AER. Includes new scheme application and scheme amendment variants.
D065 Annual Compliance Report Template
Pre-structured 11-sheet Excel workbook for Clause 21 annual progress reporting: cover page, operations summary, pressure analysis, scheme performance, MMV results, 13-parameter monthly data table per well, cumulative volume tables, Hall plot with auto-chart, daily injection plots (rate, WHP, BHIP, reservoir P), and forward-looking assessments. Yellow = input, green = auto-calculated.
AER Reference Links
AER Directive 065 — Requirements for Acid Gas Injection and CO₂ Storage Schemes
AER Directive 056 — Energy Development Applications and Schedules
AER Directive 020 — Well Abandonment Requirements
AER Directive 071 — Emergency Preparedness and Response
Carbon Sequestration Tenure Regulation — Pore space rights and liability transfer
AER OneStop — Online application submission portal
Approval Intelligence — What AER Actually Conditions
Understanding what AER conditions in approvals helps you prepare a stronger application. This annotated case study is based on CO₂ Sequestration Approval No. 13513 — a real Class III scheme approval issued March 10, 2026. Every clause is annotated with strategic implications for your application.
Case Study: Approval No. 13513
Pre-Injection Gate Conditions
AER blocks injection until ALL of these gates are cleared. Your application should demonstrate readiness for each.
Your application must include fully developed MMV, ERP, closure, and seismic monitoring plans — not placeholders. AER will not approve injection until each plan is validated. Build your project schedule around these sequential gates.
Phased Well Approval Process (Clauses 6-8)
The scheme may be approved with undrilled wells listed, but those wells CANNOT inject until a separate D065 application is submitted and approved with:
Minimum Requirements for Undrilled Well Applications
a) Geological interpretation: updated gross sand isopach map, updated storage capacity, interpreted log cross-sections with stratigraphic interpretation, completions/treatments, KB elevation, net thickness/permeability/porosity tabulation
Bounding Formation Assessment
b) Lithology, continuity and thickness of base and caprock, integrity of base and caprock, fracturing assessment (if fracturing evident, explain how containment is still assured), target zone pressure from stabilized shut-in survey (D040)
Pressure Limits
c) Bottomhole injection pressure, maximum sandface pressure, fracture propagation pressure, and formation fracture pressure for each well
Pressure Transient Analysis
d) Stabilized shut-in reservoir pressure survey per D040, accompanied by PTA that may indicate fracture flow
Model Re-runs Required
e) Must address the need to rerun CO₂ plume and pressure front dynamic models after each well is drilled
MMV Evidence
f) Evidence that current MMV plan commitments have been met
Plan your well program assuming each new well needs its own mini-application. Budget for post-drill geological interpretation, PTA, and model updates. This is not a single-approval-covers-all situation — AER validates each well individually.
The D065 application for undrilled wells must be submitted within 24 months of the approval date. AER will not grant extensions and may rescind the scheme or undrilled well approvals without further notice.
This is a use-it-or-lose-it clause. If your well program extends beyond 24 months from scheme approval, you risk losing approved well locations. Factor drilling timelines, post-drill evaluation, and application preparation into your project schedule from day one.
Operational Limits & Constraints (Clause 14)
These are the specific operational parameters AER imposed. Your application should propose limits consistent with these benchmarks.
Pressure Limits
Wells are BHP-limited and must be equipped with bottomhole pressure gauges. Maximum average formation stabilized shut-in reservoir pressure: 26,000 kPa (gauge). This becomes the scheme's pressure ceiling.
Volume Limits
Per-well maximum: 650 MMscm/yr (1.2 Mt/yr) at standard conditions (15°C, 101.325 kPa). Scheme total: 13,000 MMscm (24 Mt) cumulative across all wells.
CO₂ Purity Requirement
Injection fluid must contain no less than 95% CO₂ by volume. Monthly representative sampling of injection stream composition required. No waste or other materials may be added.
2-Year Pressure Test Cycle
Stabilized shut-in BHP test per D040 every 2 years in each injection or observation well. Supplementary surveys may be required based on results.
2-Year Hydraulic Isolation Log Cycle
Hydraulic isolation log per D051 in injection and deep monitoring wells every 2 years. AER determines if supplementary logging is needed during annual reporting review.
Annular Monitoring & Well Integrity
Continuous tubing/casing annulus pressure monitoring. Annual packer isolation tests submitted via AER DDS by Dec 31. Corrosion protection required. Emergency shutdown valves installed and periodically tested.
Immediate Suspension Triggers
Must immediately suspend injection if: (i) fluid migrates to unapproved zones, (ii) any equipment, monitoring, or safety device fails. Must immediately report loss of containment, out-of-zone fracturing, or anomalous pressure changes to ResourceCompliance@aer.ca.
Design your injection parameters conservatively relative to these limits. If you propose 90% of the pressure ceiling, AER will scrutinize harder. Leave headroom. Also budget for biannual pressure testing and isolation logging — these are non-trivial operational costs.
Post-Approval Compliance Obligations
These obligations begin the moment you receive approval. Understanding them before you apply ensures your MMV and operational plans are adequate.
Must provide an update of all drilling activity in the AOI since approval date. Confirm no new wells with potential hydraulic isolation risks. Must include risk assessment of loss of hydraulic isolation from hydraulic fracturing in overlying/underlying formations.
If there's active unconventional development (e.g., Duvernay, Montney fracking) near your CCS project, AER will want you to assess whether frac jobs have compromised the seal or created communication pathways. Address this proactively in your risk assessment.
Must provide evidence of continued maintenance of the Carbon Sequestration Tenure Agreement (CSTA) from the Alberta Crown at time of D065 submission. Must review mineral rights ownership and well licensees in the area and notify all new holders/licensees and parties with known concerns before application submission.
Your CSTA is a prerequisite — not a parallel track. Ensure your pore space tenure is current and covers all well locations. Also, mineral rights notification is a D065 requirement beyond D056 consultation — do not confuse the two.
Injection well status in Petrinex must be changed to: Fluid: CO2 | Mode: N/A | Type: INJ | Structure: CARBON SEQU as soon as injection commences. This enables recording of injection volumes and density data. Contact: pa.help@aer.ca
This is an administrative step that's easy to overlook. Have your production accounting team ready to update Petrinex codes on day one of injection. Delays here create data gaps in your compliance record.
Written incident report required within 90 days to ResourceCompliance@aer.ca AND WellOperations@aer.ca for any event posing imminent risk: (a) fracturing out of zone, (b) loss of containment, (c) unexpected surface heave. If monitoring shows loss of containment or surface heave, must conduct and submit comprehensive subsurface modelling using site-specific parameters.
Your application should include a geomechanical assessment of surface heave potential (InSAR baseline). If you don't address this upfront, AER will condition you to assess it reactively — which is more expensive and time-pressured.
Approved MMV and Closure plans are valid for 3 years from commencement of injection into any well. Updated plans must be submitted at least 90 days before expiry or when requesting significant amendments. Submissions via D065 application through AER DDS.
Your MMV plan is not a set-and-forget document. Budget for plan revisions at Year 2.5 based on operational learnings. Design your initial MMV plan with adaptive management triggers so updates are data-driven, not just calendar-driven.
Must perform, document, and submit an updated risk assessment to AER for ALL wells terminated at or traversing the target formations (abandoned, suspended, or active) within the projected plume area.
Phased Timeline
Within 3 months of injection start: Initial risk assessment covering wells likely impacted by plume within 2 years.
Within 1 year of injection start: Full risk assessment encompassing ALL wells in the projected plume area.
Medium-to-high risk wells: Must be mitigated BEFORE the fluid plume reaches them.
Start your offset well risk assessment during the application phase, not after approval. The 3-month deadline is tight. If mitigation work (squeeze cementing, re-abandonment) is needed, those wells are on your critical path.
Must submit a revised geomechanical modelling report for thermal fracturing assurance within 2 years of initiating injection, or with the first annual report (whichever is first).
Cold CO₂ injection into warm formations creates thermal stress that can fracture rock near the wellbore. Include a preliminary thermal-mechanical analysis in your application to demonstrate awareness. AER will condition you to refine it post-injection with real temperature data.
AER required a special report (due June 30, 2027) covering:
- Phased assessment of natural variability of geochemistry in domestic water wells (baseline study)
- Statistical significance methodology for number of landowner water wells in baseline data
- Potential need for downhole microseismic arrays in deep monitoring wells
- Geomechanical testing of primary seal
- Technologies for monitoring vegetation health changes due to surface leaks
These are emerging AER expectations. Address each proactively in your application: (1) design a statistically robust groundwater baseline, (2) consider downhole microseismic as part of your MMV, (3) include seal geomechanics in your caprock assessment, (4) mention InSAR and vegetation monitoring technologies. Applicants who address these upfront signal regulatory maturity.
Annual Reporting Requirements (Clause 21)
Annual progress reports due March 1 each year. The scope is extensive — your MMV plan and data management system should be designed to produce this output.
a) Operations Summary
New wells drilled, workovers/treatments, changes in injection equipment, identification of problems and remedial actions.
b) Pressure Analysis
Stabilized formation pressure surveys, comparison of actual vs. expected pressure, updated estimate of cumulative volume at max shut-in pressure (26,000 kPa).
c) Scheme Performance & Updated Models
How formation pressure is changing over time, updated geological maps, updated CO₂ plume extent and pressure distribution models using all new data since last model run.
d) MMV Results
Events exceeding approved requirements, comparison of measured vs. predicted performance, operations and maintenance summary, performance or MMV issues, pressure surveys, corrosion data, fluid analyses, logs, and discussion of MMV plan changes needed.
e) Monthly Data Table — 13 Parameters Per Well
For each well, for each month: (i) CO₂ mole fraction & stream composition, (ii) injection stream density, (iii) volume and mass at standard conditions, (iv) formation volume factor, (v) cumulative volume and mass since scheme start, (vi) volume and mass at reservoir conditions, (vii) hours on injection, (viii) max daily rate, (ix) average daily rate, (x) BHIP and wellhead temp, (xi) average BHIP and wellhead temp, (xii) BHIP at top of interval with BH temp, (xiii) average BHIP at top of interval with average BH temp.
f-g) Volume Tables & Hall Plots
Monthly and cumulative CO₂ volumes/mass. Hall plots of constant average reservoir pressure where unexplained anomalous injection rate and pressure data could indicate fracturing.
h) Daily Plots (from commencement)
Daily CO₂ injection rate, wellhead and bottomhole injection pressures, estimated or measured average reservoir pressure — all vs. time from start of injection.
i-k) Forward-Looking Assessments
Need for additional monitoring wells at pressure front periphery, need for additional deep monitoring wells adjacent to injection wells, and stakeholder engagement activities during reporting period.
This is a massive data management and reporting obligation. Your MMV plan should specify how each of these 13+ parameters will be acquired, stored, QA'd, and reported. If your data infrastructure can't produce this output, your MMV plan is inadequate. Download the D065 Annual Compliance Report Template from the Calculators & Downloads tab — pre-structured for all Clause 21(a)–(k) requirements.
Other Key Conditions
Must provide written notification upon detection of seismic events. TLP must be activated immediately. If any well becomes seismogenic, must submit seismic risk assessment and updated MMR plan per D065.
Your TLP must be operationally ready before injection starts — not a paper exercise. Define clear magnitude thresholds (typically ML 0.0 yellow, ML 2.0 orange, ML 4.0 red) and corresponding operational responses. AER Subsurface Order No. 2 provides the framework.
Scheme cannot be transferred without express written consent of the Minister of Alberta Energy and Minerals (per the CSTA). Must continue to operate per D065 as amended. AER may vary, suspend, or revoke the approval at any time if circumstances warrant.
If your business model involves eventual asset sale or transfer, understand that the Minister must consent. This adds time and uncertainty to M&A transactions. Structure your corporate arrangements accordingly from the outset.
AER Contact Directory
Different notification types go to different AER teams. Using the wrong contact creates compliance gaps.