Goal of the project
Injectivity impairment due to salt precipitation or hydration formation has been recognized as a new issue for CO2 storage. To ensure safe and long-term CO2 injection it is crucial to prevent clogging of the pore space in the near-well region or within the reservoir. The overall objective in this project was to investigate how, where and when injectivity in a CO2 well is lost due to precipitation of salt or formation of hydrates, and which operational parameters minimize the risk of reduced injectivity. We studied precipitation of salt and hydrate formation through experimental campaigns where we injected CO2 into porous rock samples. We developed mathematical models that can predict how salts and hydrates affect porosity and permeability. In addition, it was evaluated whether CO2 hydrates can serve as a self-seal above the storage zone and thus increase the security of the storage.
We performed experiments where sandstone core samples are flooded with CO2 at relevant pressures and temperatures, to induce salt precipitation or hydrate formation. The core samples were investigated using X-ray tomography and magnetic resonance imaging to determine where clogging occurs within the core and to observe distribution of salt or hydrates within the pore space. A numerical model was developed for flow and thermodynamics of CO2-water-salt/hydrate in the near-well zone.
Advantages of the project
New experimental approaches are developed for studying salt precipitation and hydrate formation which are valuable for future research in these areas. The numerical model developed uses advanced thermodynamic models to ensure a good prediction of precipitation of salt.
(1) Design experimental campaigns with realistic reservoir conditions that identify nucleation and growth mechanisms of salt/hydrate formation, as well as effects on reservoir permeability.
(2) Design and implement a numerical model that demonstrates flow and thermodynamics of salt precipitation and hydrate formation in reservoir rocks.
Results to date
The first experiment for salt clogging of sandstone cores was designed in 2016. Two supercritical CO2 injection experiments have been performed to observe salt precipitation. Innovative solutions were: (1) the injection geometry was radial, (2) a large sandstone core with borehole was used; (3) constant brine inflow from the outer surface was introduced during entire CO2 injection period. Salt precipitation was observed for the injection period of one week, but the amount of precipitation had no severe injectivity impairment effect. The results were presented at Trondheim CO2 Capture and Storage Conference in June 2017. The geometry and flow conditions in the CO2 injection experiments were used in the modelling of flow and thermodynamics of salt precipitation.
A postdoc was employed in 2016, and involved in gas hydrate experiments in a high-pressure rheometer cell. Gas hydrates formed directly in the rheometer cell, and viscosity profiles and flow properties of hydrate slurry were measured. Rheological study of hydrate formation was presented at the Annual European Rheology Conference in Copenhagen in April 2017. The following experimental work was focused on hydrate formation in sandstone in a core flooding setup where various parameters such as pressure and temperature, flow rate, brine salinity and rock pore volume saturation can be varied. Under most conditions, complete clogging with CO2 hydrates was achieved. This was followed by a study of hydrate formation at core scale using magnetic resonance imaging under realistic reservoir conditions in collaboration with Equinor, which was completed in spring 2018. The last stage was postdoc's research visit to Heriot-Watt University in Edinburgh. During this visit, hydrate formation at pore scale using reservoir rock micro-models was studied.
The implementation plan for modelling work was completed in 2016, and a model for salt precipitation in presence of CO2 and water was developed in the first half of 2017. The last half of 2017 was spent to develop a multi-phase near-well flow model that could include precipitation of solids such as salt and hydrates. The work in 2018 consisted of coupling the thermodynamic model with the flow model to predict how salt precipitation or hydrate formation affects porosity and permeability. One of the main outcomes of the modelling work is a unique simulation tool which is easily modifiable, and which uses state-of-the-art thermodynamic models. This simulation tool will be important in future competence-building and industry projects. The experimental results have been compared with the simulation tool, and the initial comparisons show that the model parameters for salt precipitation need to be adjusted to properly predict high salt concentrations.
Some of the largest uncertainties and costs of a carbon capture and storage (CCS) system are related to CO2 storage. There are still significant knowledge gaps concerning how the injectivity of a CO2 reservoir changes over time during injection. A high injectivity over time is crucial for large-scale CCS, for the reliability of a CO2 injection well, and reduces the number of wells that need to be drilled. Whether transported by ship or in pipelines, the injected CO2 will typically be colder than the reservoir. When CO2 and brine are mixed at sufficiently low temperatures, they can form a solid hydrate phase and reduce permeability. Over time, these hydrates might melt due to the heat from the surrounding reservoir, but they hinder a continuous injection of CO2 which is necessary for a cost-efficient operation of a CO2 injection well. If the injected CO2 mixture has a low water content, water will evaporate into the incoming CO2. Eventually, the brine will become oversaturated and precipitate salt crystals that clog the reservoir pores. On the other hand, for reservoirs within the hydrate stability zone, formation of CO2 hydrates above a storage zone can form a secondary seal and contribute to preventing leakage. This will increase the security of the storage and may contribute significantly towards stable storage of CO2.
In this project, we investigate when and where hydrates and salt crystals form under relevant reservoir pressures and temperatures. We perform experiments where rock samples are saturated with brine and flooded with CO2, while permeability is measured and related to porosity. We will also evaluate whether CO2 hydrates may serve as a self seal by long-term hydrate maturation tests. Thermodynamic models using state-of-the-art equations of state are developed in order to predict the conditions in which hydrate and salt forms. This can be used to determine which injection rates, temperatures and compositions are necessary to avoid loss of injectivity.