Gantt Chart for Carbon Capture and Storage Projects

Carbon capture, utilization, and storage (CCUS) is one of the most complex infrastructure project types to schedule — combining industrial process engineering, subsurface geology, pipeline infrastructure, and a regulatory framework that is still maturing. The 45Q tax credit (enhanced by the Inflation Reduction Act to $85 per tonne for geologic storage, $60 per tonne for enhanced oil recovery) has unlocked a wave of project development, but the regulatory bottleneck for CO2 injection well permitting means that the gap between project announcement and first injection is measured in years, not months. A Gantt chart that reflects the actual regulatory timeline is the difference between a project that closes financing and one that sits in development limbo.

The Two Primary CCUS Project Types

Point-source capture: CO2 is captured from a concentrated industrial emission source — cement plants, steel mills, ethanol fermentation facilities, natural gas processing plants, hydrogen production facilities, and coal or gas power plants. Point-source capture is the lower-cost option because the CO2 is already concentrated (15 to 99% CO2 depending on the source vs. 0.04% in ambient air).

Direct air capture (DAC): CO2 is captured directly from the atmosphere. DAC technology (Climeworks, Heirloom, Carbon Engineering/Occidental) is 5 to 10 times more expensive per tonne than point-source capture but can theoretically be sited anywhere with access to clean energy and CO2 storage. The DOE DAC Hub program is funding first commercial-scale projects. Show DAC on a Gantt chart similarly to point-source capture, but with more emphasis on the energy supply infrastructure (DAC requires large amounts of thermal or electrical energy).

Phase 1: Feasibility Study and Capture Technology Selection

The project begins with a feasibility study that evaluates capture technology options, CO2 purity requirements for pipeline transport and injection, energy penalty of capture (how much of the facility's output is consumed by the capture process), and preliminary capital and operating cost estimates.

Capture technology selection is a major decision that gates engineering:

Post-combustion amine scrubbing: The dominant commercial technology for flue gas capture. Monoethanolamine (MEA) or advanced solvent formulations absorb CO2 from flue gas; heat regenerates the solvent and releases concentrated CO2. Energy penalty: 15 to 30% of plant output.
Pre-combustion capture: Fuel is converted to hydrogen and CO2 before combustion; CO2 is separated from the hydrogen-rich syngas. Applicable to natural gas reforming (blue hydrogen production).
Oxyfuel combustion: Fuel is burned in pure oxygen rather than air, producing a flue gas that is primarily CO2 and water vapor — easy to capture but oxygen production is energy-intensive.
Membrane separation: Polymer or ceramic membranes selectively permeate CO2. Suitable for high-concentration CO2 streams; early commercial deployment.

Phase 2: Subsurface Characterization and Injection Well Siting

CO2 must be stored in a geological formation — typically a saline aquifer or depleted oil/gas reservoir — at depths exceeding 800 meters (where CO2 is in a supercritical state and remains dense). The storage formation must have:

Adequate porosity and permeability to accept CO2 at the planned injection rate
A competent caprock (seal) preventing CO2 migration upward
No faults or fractures that could provide migration pathways
No existing groundwater supply wells within the area of review

Subsurface characterization requires:

Geologic desktop study: Review of available well logs, seismic data, and published literature.
Seismic data acquisition: 2D or 3D seismic reflection surveys to image the subsurface structure.
Stratigraphic test well: A slim-hole well to collect core samples and verify formation properties at the storage depth.
Reservoir simulation: Numerical model predicting CO2 plume behavior and pressure buildup over the injection period and post-closure monitoring period.

Phase 3: EPA UIC Class VI Well Permitting — The Critical Path Bottleneck

The EPA Underground Injection Control (UIC) Class VI well permit is required for any CO2 injection well for geologic storage in the United States. This permit is the primary regulatory bottleneck for CCUS projects — and the most important item to show on the Gantt chart.

Class VI permit review involves:

Area of review delineation (typically a 2 to 5 km radius around each injection well)
Review of all existing wells within the area of review (abandoned wells can provide CO2 migration pathways)
Injection well construction specification review
Monitoring, verification, and accounting (MVA) plan review
Emergency and remedial response plan review

As of 2025, fewer than 15 Class VI permits had been issued nationally since the program was established in 2010. The average permit review time has been 2 to 5 years. Several states (Wyoming, North Dakota, Louisiana, West Virginia) have received EPA primacy to administer the Class VI program — state primacy programs can move faster, but they are still measured in years.

The Class VI permit governs:

Injection well construction (casing, cementing, mechanical integrity testing)
Injection rate and pressure limits
Area of review corrective action (plugging of improperly abandoned wells)
Monitoring requirements during injection
Post-injection site care (minimum 50 years of monitoring)
Financial assurance (cost of post-injection monitoring must be bonded)

Show Class VI permit application submission, agency completeness review, public comment period, and permit issuance as sequential milestones on the Gantt chart. Submit as early as subsurface characterization allows — permit review runs in parallel with capture facility design and construction.

Phase 4: FEED Engineering

Front-end engineering and design (FEED) produces the bankable cost estimate and specifications required for EPC contracting and project finance. FEED for a CCUS project covers:

Capture facility design: Absorber columns, regenerator, solvent handling, heat exchangers, utilities
CO2 compression and dehydration: CO2 must be compressed to pipeline pressure (typically 100 to 150 bar) and dehydrated (water content below 50 ppm to prevent corrosion and hydrate formation in pipelines)
Pipeline design: CO2 pipeline right-of-way, pipeline diameter, materials specification (CO2 in supercritical phase is corrosive in the presence of water — pipeline must be carbon steel with cathodic protection and careful moisture control)
Injection well design: Well casing program, cement design, wellhead equipment, downhole monitoring
MVA system design: Groundwater monitoring wells, geophysical monitoring program, surface flux monitoring

FEED typically runs 12 to 18 months.

Phase 5: Financing — The 45Q Tax Credit Structure

CCUS project finance in the United States is structured around the 45Q tax credit:

$85 per metric tonne: For CO2 geologically sequestered in a Class VI-permitted formation.
$60 per metric tonne: For CO2 used in enhanced oil recovery (EOR) and sequestered.
$130 per metric tonne: For CO2 removed from the atmosphere by DAC and geologically stored (IRA enhancement).
Direct pay: IRA allows tax-exempt entities to receive 45Q as a direct payment — critical for project developers who cannot use tax credits directly.

45Q credits run for 12 years from first carbon oxide capture. Tax equity investors (banks, insurance companies with large tax liabilities) provide financing in exchange for the credit stream. Show financing close as a milestone that gates procurement and construction.

Phase 6: Capture Facility Construction

Construction of a post-combustion amine scrubbing system at an existing industrial facility requires:

Civil and structural work: Foundations for absorber and regenerator columns (typically 30 to 60 meters tall), heat exchanger foundations, pump and compressor foundations.
Absorber column installation: Large steel vessels requiring crane erection.
Regenerator column installation: Similar to absorber.
Heat exchanger installation: Lean-rich heat exchangers, condenser, reboiler.
Solvent system: Solvent storage tanks, solvent filtration, solvent reclaimer.
CO2 compression train: Multi-stage centrifugal or reciprocating compressors, intercoolers.
Dehydration system: Molecular sieve beds or glycol dehydration.
Utility connections: Steam supply (for solvent regeneration — the largest operating cost), cooling water, electrical.
Integration with existing plant: Tie-in to flue gas duct, steam system, cooling water.

Integration with an operating industrial facility is the most challenging construction aspect — work must be coordinated with plant operations to minimize downtime.

Phase 7: CO2 Pipeline Construction

CO2 pipelines are regulated by PHMSA (Pipeline and Hazardous Materials Safety Administration) under 49 CFR Part 195. CO2 pipeline design must account for:

CO2 hydrogen embrittlement: CO2 is not compatible with conventional natural gas pipeline materials containing hydrogen (a concern for repurposing natural gas pipelines for CO2 transport).
Ductile fracture propagation: Supercritical CO2 pipelines can experience rapid crack propagation; fracture control plans and crack arrestors are required.
Depressurization: In case of pipeline rupture, CO2 rapidly decompresses; exclusion zones and emergency response plans are required.

Pipeline right-of-way acquisition is similar to natural gas pipeline development — easement negotiation with landowners along the route. PHMSA permit (or operator qualification under existing PHMSA authorization) is required.

Phase 8: Injection Well Drilling and Completion

CO2 injection wells are drilled and cased to the storage formation following the Class VI-approved design. Mechanical integrity testing (MIT) is required before injection begins — MIT demonstrates that the well casing and cement are intact and will prevent CO2 from migrating out of the storage formation.

Phase 9: MVA System Installation and Commissioning

Monitoring, verification, and accounting (MVA) systems installed before injection begins include:

Groundwater monitoring wells: Shallow wells monitoring drinking water aquifers above the storage formation for any CO2 or brine migration.
Seismic monitoring: Passive seismic network to detect any induced seismicity from injection.
Surface flux monitoring: In some cases, surface CO2 flux measurement to detect any surface leakage.

Phase 10: Injection Operations and Post-Injection Monitoring

CO2 injection begins after the Class VI permit is obtained, mechanical integrity testing is complete, and the MVA system is operational. Injection operations run for the life of the capture facility (typically 20 to 30 years).

Post-injection monitoring (minimum 50 years per EPA regulations) is the longest phase of all — it must be shown on the project timeline and bonded financially before injection begins.

Key Milestones for the Gantt Chart

Milestone	Typical Timing
Class VI permit application submitted	Year 1-2
FEED complete	Year 2-3
Class VI permit issued	Year 3-7
Financing closed	Year 3-6
Capture facility construction complete	Year 4-7
Pipeline complete	Year 4-6
Injection wells drilled and tested	Year 5-8
First CO2 injection	Year 5-9
Post-injection monitoring begins	Year 25-35

The Class VI permit timeline is the dominant schedule driver for CCUS projects. Developers who underestimate this timeline — assuming a 1 to 2 year permitting process rather than the 3 to 5 years that most projects experience — consistently fail to close project financing on their initial schedules.