CO₂ Storage

The existing oil and gas fields provide an opportunity to accelerate the permanent storage of CO₂ thanks to:

• A well-described reservoir storage capacity
• Decades of accumulated knowledge of the subsurface, both static and dynamic
• A reservoir seal which has been proven to be gas tight over geological time
• Potential to re-use infrastructures
• Long distance to shore and inhabited areas

Also revisiting relinquished exploration licenses and understanding the failing mechanism for categorised dry holes is seen as an excellent opportunity to open up additional storage capacity.

Many Danish oil and gas fields are chalk reservoirs, and questions have been raised regarding their suitability for CO₂ storage - particularly regarding rock dissolution and mechanical integrity.

To assess the suitability of chalk reservoirs for CO₂ storage, a series of research projects has investigated potential showstoppers - none were found. Overall, the conclusion of the project was that chalk reservoirs are at the same CO₂ storage maturity level as sandstone reservoirs.

One of the main challenges when re-using existing oil and gas fields for CO₂ storage is the integrity of existing well penetrations, which might result in potential leak paths if the well barriers are breached after abandonment. This is a concern as the wells and some of the abandonment barriers were designed and installed before CO₂ storage was considered.

Cement is the main barrier element in the abandoned wells, and this barrier may be affected if exposed to CO₂. Based on both experiments and modelling, research is creating an understanding of the impact of CO₂ on barrier integrity.

Using shale as a barrier material for the wells will ensure integrity over geological time. Researchers are investigating where naturally occurring shales can form part of a well barrier and thereby ensure long term integrity. The swelling capabilities will also be tested within a CO₂ environment.

When evaluating a potential storage site, it is essential to evaluate not only the potential for leakage from abandoned wells, but also to verify the integrity of the cap rock.

Researchers have developed a modelling tool, the DFM tool, which can evaluate the potential for fracture propagation in the caprock during the injection period. The purpose is to assist flow modelling in naturally fractured reservoirs by improving the characterisation and prediction of the fractures. Flow through fractures is modelled either by modifying the bulk rock properties to take account of the fracture porosity and permeability, or by generating Discrete Fracture Network models (DFNs).

In both cases, a more accurate representation of the distribution, orientation, length and connectivity of the fractures will give a better history match. Traditional fracture modifiers and DFNs are generated stochastically – fractures are placed at random, and there is little constraint on length and connectivity. Therefore, they often give poor results.

Instead, we built fracture models by simulating the nucleation and growth of the fractures, based on subcritical fracture propagation and linear elastic fracture mechanics theory. We therefore generate much more realistic fracture models which honour geology.

There is a growing need for more accurate, realistic storage capacity estimates that account for the dynamic nature of subsurface environments.

At DTU Offshore, we leverage our expertise in advanced reservoir modeling and geomechanics to address this challenge. Using THMC (Thermal, Hydraulic, Mechanical, and Chemical) modeling, we analyze how subsurface systems respond to the simultaneous interactions of multiple physical processes. These interactions include:

• Temperature: Influencing chemistry and fluid viscosity
• Chemistry: Altering porosity and permeability, which affects fluid flow
• Fluid Pressure: Impacting mechanical stresses
• Mechanical Deformation: Changing fluid flow pathways

 

A solid understanding of the dynamic behavior of the entire aquifer system - where multiple CO₂ storage sites and other subsurface activities share the same formation - is essential to prevent conflicts between future “neighbors.” When CO₂ is injected, the pressure front moves significantly faster through the saline aquifer than the CO₂ plume itself, making interference between structures both expected and necessary to understand.

The timing, scale, and operational details of each CO₂ storage project, along with other subsurface activities, determine how these systems will interact. Proper coordination is therefore critical to preventing future disputes.

It is important to dynamically simulate different injection scenarios and to model the effects of water back-production. Here, experience from advanced reservoir modelling as well as the offshore produced-water management provides valuable insight.

Monitoring of CO₂ injection is key for public acceptance of a CO₂ storage site, therefore when injecting CO₂ into the subsurface integrity must be monitored.

There is a lack of reliable and cost-effective monitoring tools for offshore storage sites. DTU Offshore is developing various types of sensors in collaboration with the industry ranging from single point sensors which can be deployed stationary or on a moving remotely operated vehicle (ROV), and sensor networks to cover a larger area.

When CO₂ storage sites are monitored a large amount of data will be collected and it can be difficult to find out when a datapoint is indicating something which might be wrong. We are therefore working on developing modelling solutions with AI tools to understand the signs of a developing leakage.

Subsurface CO₂ storage could affect the marine environment in the unlikely event of a leak. Establishing a pre-injection environmental baseline is therefore essential. Such a baseline can also be utilized to understand the collected monitoring data. Ongoing research is developing a toolbox to support effective environmental baselining of CO₂ storage sites.

If a leak occurs, the gas reaching the seabed is unlikely to be pure CO₂. Injected CO₂, containing impurities, reacts chemically and biologically with surrounding fluids - and continues to interact with formations as it migrates toward the seabed.

Ongoing research aims to determine the composition of potential CO₂ leaks and their effects on the seabed’s microbial environment.

Research is ongoing to develop software that estimates energy consumption across CCS value chains, linking European emitters with storage sites and accounting for different capture and transport methods. The software includes various capture methods, depending on the flue gas origin, and various transport methods.

When CO₂ is captured, it will include impurities. Researchers at DTU Offshore is working on understanding the impact of these impurities on the reservoir integrity and injectivity. This knowledge needs to be linked with the impact of the impurities on the transport part of the value chain to understand the overall optimal cleaning of the CO₂.

Research is ongoing to develop software that estimates energy consumption across CCS value chains, linking European emitters with storage sites and accounting for different capture and transport methods. The software includes various capture methods, depending on the flue gas origin, and various transport methods.

The offshore area will play a key role in the energy transition, in both energy generation and storage. Research is exploring whether residual hydrocarbons in depleted reservoirs can be converted to hydrogen via microbial processes.

If successful this would mean that the existing installations might produce hydrogen instead of hydrocarbons, which e.g. could be used to decarbonize offshore CO₂ storage facilities. Another research project is looking into whether CO₂ hydrates can be used for temporary storage of excess energy.