Pressure rather than pore volume usually limits storage capacity. Injecting CO2 into a saline formation displaces brine, and unless that brine can move away or be produced, pressure rises across a region far larger than the CO2 plume. That pressure increase is constrained by the fracture pressure of the caprock, by the tolerance of existing wells and faults, and by regulatory limits, and it frequently binds long before the pore space is filled. Capacity estimates based on pore volume and an efficiency factor routinely overstate what can actually be injected.

Buoyancy drives the containment problem. CO2 at storage conditions is substantially less dense than formation brine, so it rises until a barrier stops it, and it spreads laterally beneath that barrier over a large area. The caprock must therefore be continuous, of adequate capillary entry pressure and free of transmissive faults or wells across the entire plume footprint, not merely at the injection point. Characterising the seal over that area is a substantially larger task than characterising a petroleum trap.

Legacy wells are the most likely leakage pathway in mature basins. A depleted field selected for storage because it is well characterised and has proven containment may have dozens or hundreds of wells penetrating the seal, many drilled decades ago, plugged to standards of the time and with records of variable quality. Assessing their condition, and remediating those that present risk, is often the largest single technical and cost item in a storage project in a mature area.

Finally, the obligation continues after injection stops. Regulatory frameworks require demonstration that the CO2 is behaving as predicted and will remain contained, monitoring through a post-injection period, and eventual transfer of long term responsibility. This changes how a project must be characterised, modelled and monitored from the outset, because the evidence required at closure has to be planned for at the design stage.

By the end of this training, participants will be able to:

• Screen and characterise candidate storage sites against reservoir, seal and containment criteria
• Describe CO2 behaviour at storage conditions including density, viscosity, solubility and buoyancy
• Evaluate structural, residual, solubility and mineral trapping and their timescales
• Estimate storage capacity using static and dynamic methods and apply appropriate efficiency factors
• Assess pressure-limited capacity and design pressure management including brine production
• Evaluate injectivity and the factors that reduce it including drying and salt precipitation
• Predict plume migration and specify simulation requirements for storage modelling
• Assess containment risk including caprock integrity, faults and legacy wells
• Design monitoring, measurement and verification programmes to regulatory requirements
• Plan post-injection monitoring, site closure and long term stewardship

The training develops CO2 subsurface behaviour and then applies it to site assessment, capacity, injectivity and containment through calculation on real and representative storage sites. Participants estimate capacity by multiple methods and compare the results, calculate pressure build-up and its constraint on injection, and assess containment for sites with legacy well penetrations. Simulation requirements are examined through the sensitivities that matter for plume prediction. Operating storage projects and their monitoring results are examined for what has been demonstrated and what remains uncertain.

Organisations sending participants to this training will:

• Screen and rank storage opportunities on sound technical criteria
• Produce capacity estimates that reflect pressure constraints rather than pore volume alone
• Identify containment risks including legacy wells before project commitment
• Design monitoring programmes that will satisfy regulatory requirements
• Improve injection strategy and pressure management to sustain injectivity
• Build internal capability for a growing area of subsurface activity

Participants will:

• Apply reservoir engineering to storage rather than production objectives
• Estimate and defend a storage capacity figure
• Assess containment and identify the pathways that matter
• Specify monitoring programmes against regulatory demonstration requirements
• Understand the obligations that continue after injection ceases
• Build a capability transferable from petroleum reservoir engineering

• Reservoir engineers moving into CO2 storage work
• Geoscientists characterising storage sites
• Simulation engineers modelling CO2 injection and plume behaviour
• Well and integrity engineers assessing legacy and injection wells
• Project engineers developing CCUS projects
• Regulatory, permitting and compliance staff
• Technical and commercial staff evaluating storage opportunities

Upon successful completion of this training course, delegates will be awarded an official Certificate of Completion issued by the Petroleum Engineers Association (PEA), an ISO 9001:2015 certified training organization. The certificate carries 10 Credits and formally records the total learning hours completed.

Each certificate is signed by the Course Facilitator and the CEO of the Petroleum Engineers Association, and serves as verifiable proof of professional training that delegates can present to employers and professional bodies worldwide.