Understanding the displacement and trapping of a displaced phase in porous media is important for applications in improved oil recovery (IOR) and carbon capture and storage (CCS). In IOR, we design the process to leave as little residual oil behind as possible, while for CCS, we do the opposite: we wish to maximise the amount of CO2 trapped by the host brine. Reservoir rocks display a range of wettability, from being preferentially water-wet they spontaneously imbibe water to oil-wet, or water repellent. Many rocks are mixed-wet, with both water-wet and oil-wet pores. The other wettability state is more intermediate-wet where, as we show, the rock appears to be largely non-wetting to both oil and water. Carbonate reservoirs, which house the majority of the world's remaining conventional oil, and which offer potential storage locations for carbon dioxide, have an altered wettability after contact with crude oil. In this thesis we study spontaneous displacement and trapping in carbonate rocks for different wettability conditions. The rate of spontaneous imbibition governs the rate with which oil, or carbon dioxide is trapped, while the residual saturation quantifies how much trapped. This is particularly important in carbonate reservoirs, which are almost extensively fractured. In these reservoirs, the principal mechanism for displacement is spontaneous imbibition of water to displace oil (or carbon dioxide) in the water-wet portions of the pore space. Pore structure and wettability are two of the main factors affecting displacement and capillary trapping. Experimental and pore-scale modelling studies have found a monotonic increase of residual non-wetting phase saturation, Snwr, with the initial non-wetting phase saturation, Snwi in a water-wet medium. However, altered-wettability systems have received relatively little attention, particularly those which are intermediate-wet. We first present the three carbonates we study in this thesis: Estaillades, Ketton and Portland. These are three quarry limestones that have very different pore structures and span a wide range of permeability. We present standard core analysis results including mercury injection capillary pressure and nuclear magnetic resonance response. We also study three-dimensional X-ray images of these samples, obtained at a resolution of a few microns. We use these experiments to assess the pore size distribution; we show that all the samples have micro-porosity and use the results to interpret the trapping and displacement experiments performed later. We then perform spontaneous imbibition experiments in these three carbonates under strongly water-wet conditions. We use scaling equations and recently published analytical solutions to assess the recovery of these rocks. We perform two sets of experiments. In the first, we measure the mass of water imbibed as a function of time. We show that the amount imbibed scales as the square root of time. In the second series of experiments, we measure saturation profiles as a function of distance and time using X-ray CT scanning. We demonstrate that the saturation profiles are functions of distance divided by the square root of time. We also demonstrate that the profiles are consistent with the analytical theory and, using reasonable estimates of relative permeability and capillary pressure, we can match the experimental results with the analytical solutions. We discuss how, in combination with conventional measurements of relative permeability (steady-state or using Buckley-Leverett theory in an unsteady-state experiment) these measurements could be used to measure capillary pressure and relative permeability. In the next phase of the study, we use organic acid (cyclohexanepentanoic acid) to alter the wettability of our samples and observe the relationship between the initial oil saturation and the residual saturation. We take cores containing oil and a specified initial water saturation and waterflood until 10 pore volumes have been injected. We record the remaining oil saturation as a function of the amount of water injected. In the water-wet case, with no wettability alteration, we observe, as expected, a monotonic increase between the initial and the remaining oil saturation. However, when the wettability is altered, we observe an increase, then a decrease, and finally an increase in the trapping curve for Estaillades limestone with a small, but continued, decrease in the remaining saturation as more water is injected. This behaviour is indicative of mixed-wet or intermediate-wet conditions as there is no spontaneous imbibition of oil and water. However, Ketton did not show indications of a significant wettability alteration with a similar observed trapping profile to that observed in the water-wet case. Portland limestone also showed a monotonic increasing trend in residual saturation with initial saturation but with a higher recovery, less trapping, than the water-wet case. Again, this is intermediate-wet behaviour with no spontaneous imbibition of either oil or water, and slow production of oil after water breakthrough. Finally, we repeat the same experiments but instead we age the three carbonates with a high asphaltenic content and high viscosity crude oil at 70C mimicking reservoir conditions. The results show a monotonic increase in residual saturation as a function of initial saturation but with higher recovery than the water-wet cases for Estaillades and Portland, with again no indication of wettability alteration for Ketton. We discuss the results in terms of pore-scale recovery process and contact angle hysteresis. We observe recovery behaviour that lies between the water-wet and mixed-wet conditions previously studied in the literature. Overall, the thesis demonstrates that recovery rate and the amount of trapping are sensitive to pore structure and wettability. Very different recovery trends were observed for three rocks with similar chemical composition. The work serves as a benchmark for further modelling and experimental studies. The recommendation is to reproduce, in the laboratory, conditions close to those observed in the reservoir, and to use imbibition and displacement measurements to quantify and constrain multiphase flow properties.
| Identifer | oai:union.ndltd.org:bl.uk/oai:ethos.bl.uk:679675 |
| Date | January 2014 |
| Creators | Alyafei, Nayef |
| Contributors | Blunt, Martin |
| Publisher | Imperial College London |
| Source Sets | Ethos UK |
| Detected Language | English |
| Type | Electronic Thesis or Dissertation |
| Source | http://hdl.handle.net/10044/1/29415 |
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