CCUS Projects and Carbon Dioxide Injection

Carbon dioxide phase diagram

CO₂ is solid below 56,4 degrees Celsius. When warming up under low pressure, the solid CO₂ will turn into gas whilst under higher pressures (above 5-73 bar depending on the temperature) the solid (frozen) CO₂ will turn into a liquid as shown in the chart.

More importantly for CCS, however, is the triple point at 31,1 Degrees C and 73,8 bar as these pressure and temperature boundaries will likely be passed during transport.

These three distinctly different phases have very different properties with sharp transitions. The chart also shows a subcritical liquid and gas however, these boundaries are less abrupt. Zooming in on the P and T conditions that are important for CCS the above chart was refined using the CO₂ density calculator.

The dotted lines are iso-density lines and show the very sharp density variations around the triple point both moving from gas to liquid and from gas to the supercritical phase. These density variations go hand in hand with strong cooling during pressure drop (moving from supercritical to gas) or heating during compression. A density cross-section for a constant temperature (40 degrees C) and variable pressure is shown in the Figures in the middle and to the right. The transition from liquid to supercritical phase with varying temperatures is much more smoothly as shown for a density cross-section at 200 Bara.

Impact on carbon dioxide transport and storage

When a reservoir, at say 3km depth, is heavily depleted and CO₂ is injected into this reservoir in the liquid phase below 30 degrees C, due to the cooling in the pipeline, injection into the reservoir will occur at a very high pressure overbalance due to the weight of the CO₂ column in a 3km deep well with a fluid density of around 0.9. This high overbalance and resulting expansion either deep in the completion or in the reservoir will cause a very strong cooling effect (Joule Thomson) at or near the perforations.

CCUS projects and Carbon Dioxide Injection in the gas phase

If we take an example like the Porthos project with a reservoir at a depth of 3 km and a current (heavily depleted) reservoir pressure of 20 Bara, CO₂ can initially only be injected in the gas phase to avoid this high overbalance. Due to the rapid expansion and associated cooling, freezing of water present in the reservoir would cause severe injectivity problems. As we see from the phase diagram such an overbalance can only be achieved by avoiding the CO₂ liquid phase with low-pressure transport through heated pipelines.

The 4 steps of the process of transporting the CO₂ in the gas phase from the source into the reservoir in P and T space is depicted in the next figure by the red line. This involves:

1. (minor) compression at the source
2. cooling  and some pressure drop during transport in the pipeline
3. further pressure drop at the platform to avoid a high overbalance and
4. injection into the reservoir from wellhead to perforations

With a CO₂ density in the gas phase varying between 0,1 and 0,15 and a completion-length of 3000 meters. this causes a 30-45 Bara pressure increase between wellhead and perforations. The resulting 40-50 Bara bottom hole pressure at the perforations is sufficient to inject into a reservoir initially pressured at 20 Bara. It is worth noting how close this profile comes to the hydrate formation envelope due to cooling in the pipeline and during expansion on the platform. The pressure drop/expansion at the platform helps to avoid the CO₂ getting close to the phase boundary with the supercritical phase in the completion phase. I have assumed that CO₂ warms up in the completion by some 30 degrees due to the geothermal gradient.

With rising reservoir pressure due to injection (especially around the subsurface injection points), the injection pressure will have to rise as well, which can be done for a short period in the gas phase by reducing the expansion at the platform. When pipeline pressure increases this process brings the CO₂ even closer to the phase boundary and the hydrate envelope and can only be done with dry CO₂ and very careful pressure control to avoid multi-phase flow whereby the base of the completion is most at risk as at higher pressures the CO₂ density goes up to 0,2. This is shown in the next figure by the orange-brown dashed line for a 50 Bara reservoir pressure.

CCUS projects and Carbon Dioxide Injection in the liquid or supercritical phase

When CO₂ is compressed, transported and injected in the liquid or supercritical state (above 75 Bara) the CO₂ moves between the liquid phase into the supercritical phase. At these pressures, density variations are small and transitions are expected to be smooth although viscosity will change. With densities of 0,9 to 1, reservoir pressures at 3km depth should be well above 250 Bara to avoid a very large overbalance due to the weight of the liquid or supercritical CO₂ in the 3km completion. Hydrate formation in the pipeline may also play a role when the transported CO₂ contains water and cools off due to seawater temperatures between zero and fifteen degrees C.

For the Porthos situation with a reservoir at 20 bara, CO₂ injection in the gas phase is initially required. When during injection, the reservoir pressure has increased to the level that the CO₂ in the reservoir is in the supercritical phase (above 73.8 Bara) the whole transportation strategy has to change. Crossing the phase boundaries needs to be very well understood as it will happen at different times near the completions and further away in the reservoir.

As reservoir temperatures are well above the critical 31.1 degrees, density changes are less abrupt.  However, due to the cooling of the CO₂ in the pipeline, transport tends to mostly be in the liquid phase. If this liquid CO₂ with densities of around 0.85 (black dotted line A in fig. 7) is directly injected into the wells, this will cause an enormous overbalance of up to 250 Bara (situation A) at the perforations at 3km depth. Together with the cold temperature of the CO₂ this would cause fraccing of the reservoir and could jeopardize containment. Dropping the pipeline outlet pressure is not attractive as lowering it by more than 30 Bara would bring the CO₂ back into the gas phase and less than 30 Bara would still cause an enormous overbalance. One way to overcome this problem is by lowering the CO₂ density by raising the CO₂ temperature at the wellhead (situation B in the next figure).

The impact of raising the temperature of the CO₂ at the platform to say 70 degrees C whilst keeping the pressure around 80 Bara (allowing it to expand), would lower its density at the wellhead to about 0,2. Within the completion with depth, density would rise to somewhat over 0,4, resulting in a pressure increase in the completion of some 90 Bara. This reduces the overbalance at the perforations compared to situation A by some 150 Bara. A warmer CO₂ would also reduce the fracking caused by thermal differences.

However, many offshore injection platforms may not have the opportunity to heat the CO₂. An alternative is to heat the CO₂ at the source and transport the CO₂ in an insulated and heated pipeline whereby the temperature of the CO₂ is kept above 70 degrees C (situation C). This will have a significant cost impact and probably would limit the CO₂ transport to near-shore structures (the Porthos solution).

Another, all be it much more expensive, the solution is to transport the CO₂ in the gas phase and heat and compress the CO₂ at the platform whereby also the temperature will go up (inverse Joule Thomson effect). Not only would this require compression at the platform resulting in a higher Capex and Opex (rotating equipment, manning) but it would also bring the CO₂ very close to the triple point and compressors could struggle to handle these extreme density variations and multi-phase flows. A likely less expensive option would be to transport the CO2 first in the gas phase and later in the (heated) supercritical phase by ship to avoid the cooling in the pipeline.

Conclusions on CCUS projects and Carbon Dioxide Injection

When the reservoir pressure at the start of the CO₂ injection is significantly higher, such as with injection into a reservoir with limited depletion or directly into a saline aquifer, these problems described above, do not occur. However, these traps tend to have less storage space or maybe less reliability in terms of long-term containment.

Depleted gas reservoirs that are most suitable for CO₂ injection are those that are

1. Very close to compression facilities or
2. Have a relatively high pressure at the end of production (this could be created by dump flooding ahead of injection) or have
3. Very large storage space (thick and/or very extensive reservoirs) to warrant the high costs of additional compression and/or heating

https://www.intechopen.com/books/carbon-capture/phase-equilibria-for-carbon-capture-and-storage

https://blog.sintef.com/sintefenergy/ccs/CO2-mixture-property-knowledge-needed/

An article by Hans Goeijenbier