Reservoir Condition Pore-scale Imaging of Multiple Fluid Phases Using X-ray Microtomography

Carbon Capture and Storage is the process where CO₂ is captured from large point sources and stored in porous rock, displacing resident brines so that it remains in the subsurface for hundreds to thousands of years¹. The CO₂ resides in the subsurface as a dense super-critical phase (scCO₂), with properties radically different to CO₂ at ambient conditions. There are four principal mechanisms by which scCO₂ might be immobilized in the subsurface: stratigraphic, solubility, mineral and residual trapping. Stratigraphic trapping is where CO₂ is held underneath impermeable seal rocks; solubility trapping is where CO₂ dissolves into the resident brine surrounding the injected CO₂^2-4; mineral trapping is where carbonate mineral phases are precipitated into the rock⁵; and residual or capillary trapping is where CO₂ is held by surface forces as tiny droplets (ganglia) in the pore-space of the rock⁶. This can occur either naturally, by the migration of the CO₂ plume^7-9, or can be induced by the injection of chase brines¹⁰. In order to understand the processes governing the flow and trapping of this CO₂ in the subsurface a new suite of experiments must be conducted, harnessing new advances in technology to better understand the fundamental physics associated with multi-phase flow.

X-ray microtomography has developed as a technique over the past 25 years from early attempts to visualize both dry geological samples¹¹ and multiple fluid phases¹² to the primary method for the non-invasive imaging of rock cores, both for modeling purposes and for experimental implementation^13-15. Because microtomography is non-invasive, it has the ability to study systems at representative conditions, which is particularly attractive for the CO₂-brine-rock system, as the multiphase flow behavior of scCO₂ is highly dependent on thermo-physical properties, such as interfacial tension and contact angle, which are in turn a strong function of system conditions such as temperature, pressure and salinity^16-18. In such a complex system, with such an extensive and poorly understood set of inter-dependent variables, experiments using idealized pore structures¹⁹ or analogue fluids^20,21 may not be applicable to flow processes in the subsurface. Imaging multiple fluids at conditions representative of a prospective CO₂ injection formation has, however, remained a challenge²². In this study we outline a methodology for the examination of multi-fluid behavior at reservoir conditions, focusing on the examination of capillary trapping^23,24. This will include the designing of an imaging strategy, the assembly of the fluid cell, the injection strategy and subsequent image processing.

The experimental examination of pore-scale multiphase flow behavior in real rock systems focuses on the imaging of partially saturated rock cores after both non-wetting phase injection (drainage) and wetting phase injection (imbibition). These fluids are injected by connecting the cores to fluid injection pumps using flexible flow lines, while confining the core using a Hassler-type coreholder design²⁵. To successfully image the in-situ arrangement of scCO₂ and brine, a novel and highly sensitive experimental setup was used, primarily focusing on the use of a high resolution x-ray microscope^23,24,26. The requirements for conducting experiments at elevated temperatures and pressures are very stringent, and require recent developments in both materials technology and micro-CT facilities. The key requirements that have to be fulfilled are that any core/sample holder needs to be able to withstand high pressure high temperature (HPHT) conditions while remaining sufficiently x-ray transparent to allow for effective imaging. Lab-based instruments impose an additional constraint, as the core-holder must be small enough such that the x-ray source can be placed close to the sample and that sufficiently large geometric x-ray magnification can be achieved such that the pore space is effectively resolved. Although this constraint has been relaxed somewhat with the introduction of secondary optics in newer lab-based micro-CT machines, it has not been completely removed, especially if rapid acquisition times are desired, as higher optical magnifications tend to increase the time required to acquire images.

Experiments with soluble fluids provide an additional challenge when using lengthy acquisition times, as CO₂ will diffuse through the polymeric portions of the experimental assembly, reducing the in-situ fluid saturation. All these issues meant that scan times longer than around 2 hr were impractical. In order to keep scan times below this requirement, particularly stringent for lab based sources, the core-holder must be around 1 cm in diameter. A larger coreholder size would have required the detector to be much further from the source to achieve the same geometric magnification, reducing the x-ray flux incident on the detector and therefore increasing required projection exposure times. The flow cell used in these experiments was based on a traditional Hassler cell design, built around a carbon fiber sleeve, with a sleeve design similar to that used by Iglauer et al.²⁷, but with two significant alterations: 1) The carbon fiber composite used in the sleeve manufacture was changed from T700 fibers, with a stiffness of 230 GPa, to M55 fibers, with a stiffness of 550 GPa. This not only reduced the amount of sample movement during tomography acquisition, but also increased the maximum working pressure of the cell from 20 MPa to 50 MPa. 2) The sleeve has been elongated from 212 mm to 262 mm to allow the source and detector to be as close to the sample as possible.

A major experimental shortcoming in the first study to use micro-CT to examine CO₂ at reservoir conditions was the use of metal lines to control the flow to and from the core-holder²⁷. As the sample is rotated relative to the pumps, the flow lines also need to be rotated. Stiff flow lines can cause the sample to move, reducing effective image resolution or making some or all of the dataset unusable. To prevent this we replaced all the flow lines close to the rotation stage with flexible polyether ether ketone (PEEK) tubing. These flow lines were flexible, providing very small lateral forces (load) to the core-holder during acquisition. We also attached the flow lines to valves attached to the sample stage, rather than attaching the flow lines to the coreholder. This meant that any existing flow-line load was transmitted directly to the stage, rather than to the sample, reducing the probability of sample motion. A major disadvantage of using the PEEK tubing was that CO₂ was able to slowly diffuse through it, over a timescale of around 24 hr. This meant that CO₂ saturated brine left in the flow lines would gradually desaturate.

Another major experimental shortcoming of previous studies was inaccurate control of temperature. This can impact results in a number of ways. Firstly, temperature is a strong control on both interfacial tension and contact angle^16-18. Moreover, the solubility of both scCO₂ and carbonate rock in brine is also highly temperature dependent²⁸. Solubility control is critical, as when scCO₂ is injected into a saline carbonate aquifer it will dissolve into the resident brine, forming a highly reactive carbonic acid, which will in turn start to dissolve any calcite present. Any inaccuracy in solubility control can therefore lead to scCO₂ dissolution/exsolution or solid dissolution/precipitation.

Previous studies²⁷ used a heated confining fluid to heat the coreholder; however this was problematic. It has the disadvantages associated with the difficulty of accurately maintaining a constant confining pressure using a recirculating water supply, requiring extra heating baths for that supply. Furthermore, this system only maintains an accurate control of temperature at the point of the heating bath (not at the point of the core holder, and the confining fluid would cool between the water bath and the core holder). It also requires both an inlet and an outlet port for the confining fluid, increasing the number of fluid lines attached to the coreholder and so increasing flow line load.

Instead of using a heated confining fluid, a flexible heating jacket was used to surround the core holder. This very simple heating method resulted in very little coreholder load, and allowed for the precise and accurate heating. An extremely thin polyimide heating film was used, in order to minimize sample size. The construction of this film consists of an etched copper foil element 0.0127 mm thick, encapsulated between two layers of 0.0508 mm polyimide film. The copper elements present in the jacket did not noticeably affect image quality. Temperature was measured using a thermocouple sitting in the confining annulus of the cell. It was positioned on the outside of the confining sleeve, as close as possible to the core, ensuring an accurate, reliable and stable reading of the pore-fluid temperature. The thermocouple and heating film were connected to a custom built Proportional Integral Derivative (PID) controller, and temperatures were controlled within ± 1 °C.

To maintain complete control over inter-phase solubility, and represent conditions present in the aquifer far away from the injection site, prior to injection the brine was equilibrated with scCO₂ by vigorously mixing the two fluids together with small particles (1-2 mm) of the host rock in a stirred and heated reactor. All wetted components within this reactor are made of Hastelloy to minimize corrosion. The reactor contains a filtered dip tube to allow for denser fluid to be extracted from the base of the reactor (brine) and less dense fluid to be extracted from the top of the reactor (scCO₂). High pressure syringe pumps were used to maintain pressure and control flow in the pore-space of the rock and in the reactor, with a displacement accuracy of 25.4 nl. The experimental apparatus used in this study is shown in Figure 1. The ionic salt used for the experiment from which the representative results were drawn was Potassium Iodide (KI), as it has a high atomic weight and so a high x-ray attenuation coefficient, making it an effective contrast agent. Less attenuating salts (such as NaCl) or mixtures could be used, however larger salinities would be required to achieve the same x-ray attenuation.