Schedule carbon capture and storage projects with a Gantt chart. Covers EPA UIC Class VI permitting, capture facility construction, CO2 injection wells, and monitoring.
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.
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).
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:
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:
Subsurface characterization requires:
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:
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:
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.
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:
FEED typically runs 12 to 18 months.
CCUS project finance in the United States is structured around the 45Q tax credit:
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.
Construction of a post-combustion amine scrubbing system at an existing industrial facility requires:
Integration with an operating industrial facility is the most challenging construction aspect — work must be coordinated with plant operations to minimize downtime.
CO2 pipelines are regulated by PHMSA (Pipeline and Hazardous Materials Safety Administration) under 49 CFR Part 195. CO2 pipeline design must account for:
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.
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.
Monitoring, verification, and accounting (MVA) systems installed before injection begins include:
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.
| 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.