This thesis explores the occurrence of salt dry-out and hydrate formation when injecting CO2 into porous media. In large-scale CCS projects, injecting CO2 can potentially lead to salt precipitation or hydrate formation. These processes diminish injectivity and negatively alter reservoir rock properties. To gain deeper insight, experiments were conducted utilizing microfluidic setups, which allow for visual observation of salt-crystal or hydrate formation. Using microfluidic chips, ten salt dry-out experiments were conducted with varying pore sizes and six hydrate experiments were conducted with varying pulse trigger times. For the dry-out experiments, it was shown that salt crystals form mostly at the outlet side and that heterogeneity has a large impact on the precipitation process. A heterogeneous pattern results in a shift in salt distribution to the small pores, with results showing salt saturation at 7% in the small pore section of the medium-small pore chip, exceeding the 3% in the larger pore section. This shows the significant role of capillary action on salt precipitation. Results highlight that higher CO2 flow rates accelerate water evaporation and salt formation, yet final salt precipitation levels remain similar across varied flow rates. For instance, in the small pore size chip, final salt saturation was observed at 7% with a flow rate of 4.38 mm/s, decreasing to 4% at 0.78 mm/s. Additionally, the importance of high water saturation for salt dry-out and the impact of water backflow is shown. For hydrate formation, the importance of temperature and pressure was noted in these experiments. Three different pressure pulses were employed: manual control, a 0.5-second electronic pulse, and a 0.2-second electronic pulse, which all showing great effect on hydrate formation, yet no correlation could be determined between pulse length and hydrate saturation. Specifically, manual control yielded a 15% hydrate saturation with a 9.4% conversion factor, while the 0.5-second pulse achieved a 7% saturation and 9.1% conversion factor. The 0.2-second pulse resulted in 8% saturation and a 5.9% conversion factor. For the dissociation, the large effect of temperature was observed. All experiments showed a stable hydrate concentration, and a dissociation temperature between 5 and 9°C where temperature differences as small as 0.1°C were shown to be the difference between no dissociation and complete disappearance of all hydrates. Next to this kinetics, an interesting observation regarding the hydrate morphology was made. In addition to the five hydrate morphologies found in literature, a sixth, ‘sheet’-like type was observed.

The increasing levels of carbon dioxide (CO2) emissions in the atmosphere are significantly contributing to climate change. One approach to mitigate this issue is through Carbon Capture and Storage (CCS) techniques, which involve storing CO2 emissions underground. Depleted reservoirs are a potential option for subsurface CO2 storage. However, a challenge arises due to the disparity between injection pressure and reservoir pressure. When CO2 is injected into the reservoir, it undergoes expansion and cooling (known as the Joule-Thomson cooling effect), potentially leading to the risk of CO2 hydrate formation when it interacts with connate water.
CO2 hydrates pose a considerable threat to the success of CCS projects, as they can decrease injectivity near the wellbore, resulting in technical complications and increased costs. Thus, a thorough understanding of CO2 hydrate formation is imperative for the planning of robust and sustainable CCS initiatives. This study aims to elucidate the specific conditions under which CO2 hydrates are formed in a porous media and to assess their impact on injectivity decline.
The investigation begins with a core flooding experiment designed to delve into the physical processes involved in CO2 hydrate formation and dissociation. It also explores potential methods for prevention, mitigation and remediation. In total, results from 13 experiments are presented, with nine conducted by the author and four provided by the Advanced Sub-Surface Energy Transition (ASSET) research team.
Subsequently, an empirical numerical reservoir simulator is developed to model the formation and dissociation of CO2 hydrates within the reservoir. The empirical model facilitates a sensitivity analysis of the parameters that influence hydrate formation and allows for the assessment of the efficacy of prevention techniques examined in the laboratory setting.
The core flooding experiment helped to establish that hydrate formation is contingent upon specific pressure and temperature parameters within the hydrate stability zone. The experiment also delved into the impact of water saturation, connate water salinity, and the use of thermodynamic hydrate inhibitors (THIs) on the hydrate formation process. Furthermore, the experimental procedure facilitated the testing of prevention and remediation techniques after hydrate formation, including thermal stimulation and THIs injection.
The empirical model, developed based on an existing model shared by Kahrobaei and Farajzadeh (2022), served as a representation of the CO2 injection process in a depleted gas reservoir. It enabled a sensitivity analysis to identify the main parameters that affect hydrate formation. Additionally, the model investigated the resulting reduction in permeability, which ultimately led to diminished injectivity and increased injection pressure due to hydrate formation.
Ultimately, both experimental and numerical approaches showed that the formation of hydrates leads to a reduction in permeability, thereby diminishing injectivity and elevating injection pressure.

Underground Hydrogen storage (UHS) is an attractive technology for large-scale energy storage. The UHS safety and efficiency depends highly on accurate characterization of H2 interactions with reservoir fluids, specially wettability analyses for H2/brine/rock systems. This thesis reports experimental measurements of advancing and receding contact angles of H2/water, N2/water and CO2/water systems at P = 10 bar and T = 20 °C using a microfluidic chip (channel widths: 50 - 130 μm). The results indicate strong water-wet conditions with H2/water advancing and receding contact angles of respectively 13 - 39°, and 6 - 23°. It was found that the contact angles decrease with increasing channel widths. Little hysteresis was measured, and consequently, the results are not in line with Morrow’s curve. The receding contact angle measured in the smallest channel agrees well with the literature coreflood tests. The N2/water and CO2/water systems showed similar behaviours as the H2/water system.

Global energy demand is on the rise while efforts are being undertaken to increase the share of renewables to the energy mix. Even though, it is expected fossil fuels will remain an important contributor to meet this demand in the following decades. This can be attributed to the existing infrastructure, fossil fuels abundance, their energy density and ease of distribution.
As of today, in the oil and gas industry, competing oil-recovery techniques are screened and evaluated with cashflow based methods such as the Net Present Value rule. This method is entirely based on economics and may neglect important aspects related to the techniques. If fossil fuels will still be produced, their contribution to climate change should be mitigated. This can be achieved by considering the efficiency of the techniques employed for extraction. Additionally, the oil and gas industry is subject to uncertainty as the oil price is volatile, as has been observed in the past few years. In order to evaluate competing techniques, it is advisable to also consider the impact of this uncertainty in their evaluation.
In this thesis, the applicability of two concepts for the screening of competing oil-recovery techniques is explored. The thermodynamic efficiency is assessed with the use of Exergy analysis and the uncertainty on the price of oil is considered through the use of Real Option theory.

As the world population is projected to keep growing over the next decades, an increase in energy is required and hydrocarbon fuels will remain as the primary source of energy. Since most of the hydrocarbon resources have been discovered, it is necessary to extend the use of Enhanced Oil Recovery (EOR) methods on these mature fields to increase the fraction of oil recovered. Foam-EOR has shown to improve sweep efficiency during gas injection. However, there are two challenges regarding the use of foams: 1) the performance of the surfactants needed to generate foam and 2) the cost of these surfactants. In this study the performance of six surfactants was tested for steam foam applications; focusing on solubility, thermal stability, foam stability and adsorption in porous media. The solubility of the surfactants ranged from good to poor. However, poor solubility can be enhanced by heating up the solution. The surfactants tested showed a large range of stability behavior, from very good to very poor. The surfactant with the best thermal stability at 275°C has a molecule with three characteristics related to high thermal stability: 1) Sulfonate head, 2) aromatic compound attached to the head, and 3) a long hydrophobic tail (above 18 carbon atoms). The other surfactants, with a low to very low thermal stability lacked one or more of these characteristics. The surfactant with the best thermal stability also had the best foam behavior in porous media at 180°C, showing a max. apparent viscosity of 0.42 Pa·s and a Mobility Reduction Factor of 2818. Finally, for this surfactant, the dynamic adsorption in Bentheimer sandstone was 0.059 mg/grock at 120°C. Additionally, an exergy analysis was carried out to assess the cost of the surfactant from a thermodynamic point of view. For this purpose, the Exergy Recovery Factor was calculated for a system on which the Water Alternating Gas (WAG) and Surfactant Alternating Gas (SAG) EOR methods are applied, with different gases injected. The system includes from the initial capture of the gas and transport of the gas to the final oil and gas production from the reservoir and separation and recirculation of produced fluids. Despite the high exergy cost of the surfactant, the exergy recovery factor was higher for SAG than for WAG, meaning that more energy is extracted than invested. It was also found that less CO2 was produced per barrel of incremental oil extracted with SAG than with WAG.

Gas injection processes suffer from poor volumetric sweep efficiency due to phenomena such as viscous fingering caused by density contrast between the injected gas and the displaced fluid, channeling due to heterogeneities in the reservoir and gravity override due to the inherent lower density of gas. One possible way to overcome these negative effects is by foaming the gas. Foam can be defined as a dispersion of gas separated by lamellae in a continuous liquid phase. Lamellae stability is enhanced by adding surfactants to the aqueous phase (Lake, 2014). The underlying idea is that the pitfalls of gas injection can be overcome by trapping the gas and therefore reducing its mobility. The benefits of foam flooding have been reported by several authors (Almaqbali et al., 2017, Li et al., 2009, Chalbaud et al., 2002, Patil et al., 2018 ) however, to implement field scale projects, an accurate representation of foams in models that can be applied to reservoir simulators is of paramount importance. In this sense, two main families of foam modelling exist today. One family referred as population balance models, treat foam texture and bubble size explicitly and another family, that treats foam texture implicitly by applying a mobility reduction factor to gas mobility.
In the first part of this document, a model that treats foam texture implicitly will be used to evaluate foam performance in a heterogenous reservoir consisting of two layers with different permeabilities. The model known as STARS (Computer Modelling Group, 2010) reduces gas mobility using semiempirical functions that represent the physics governing foam texture. One of the functions used by the model is the dryout function, which represents the effects of water saturation on foam coalescence. This function is tuned by a couple parameters, namely, fmdry and epdry that control the water saturation at which foam dries out and how fast it dries out, in other words, how abrupt its collapse is. Farajzadeh et. al, (2015) found that these parameters were permeability dependent.
Inspired by these findings, in the modelling section of this project, foam performance in a two layer reservoir with different permeabilities under varying injection conditions is assessed. Each layer will have its unique set of parameters, namely, fmmob, epdry and fmdry. We are interested in seeing the effects that epdry has on foam performance and the effects of having vastly contrasting foam strengths between layers (large fmmob contrast). The results suggest that epdry can have significant impact on foam performance in the high quality regime. Interestingly, it was found that large fmmob contrast reduce vertical conformance and can reduce recovery efficiency in the high quality regime.
It is known that oil can have negative impact on foam stability, however most studies treat gas and oil as different phases. Under miscible conditions, oil and gas become one phase and the extent to how oil destabilizes foam is not clearly understood. Kahrobaei et. al (2017) found in core flood experiments a unique rheological behavior in foams with miscible mixtures of Carbon Dioxide – Decane. Their experiments showed three distinguishable apparent viscosity regimes depending on Carbon dioxide fraction. Regime 1, in which apparent viscosity increased with increasing CO2 fraction; Regime 2 in which apparent viscosity decreased with increasing CO2 fraction; and Regime 3 in which apparent viscosity is constant independently of the CO2 molar composition.
Inspired by Kahrobaei et. al, (2017) findings, the second part of the project attempts to investigate, using microfluidics, the effects in foam texture caused by compositional changes in an AOS surfactant solution and a miscible Carbon Dioxide – Decane mixture. Unfortunately, due to set-up limitations and inability to reliably mix the components, the experiments were inconclusive. Nonetheless, valuable lessons learnt are presented that will facilitate the experimental approach if someone decides to continue with this line of investigation.

Usually, oil fields are developed over three stages. First is the primary oil recovery, where the natural underground pressure is used to drive the oil to the surface. Afterwards is the secondary oil recovery, usually by water flooding or gas injection. However, the water flood yields lower sweep efficiency in heterogeneous reservoirs, contrary to homogeneous reservoirs. Tertiary flooding methods are applied to increase the oil sweep efficiency, hereby improving the efficiency of the extraction process. These methods include injection of gas and chemical solutions. This study focusses on the polymer flooding method. Polymers are used to adjust the mobility ratio (M) between oil and the displacing fluid, where the viscosity of the displacing fluid is increased significantly. However, rock-fluid interaction might affect the viscosity of the polymer, which in turn affects the mobility ratio.
A series of core flood experiments were conducted, where rock-fluid interaction likely affects the viscosity of the polymer. Hydrolyzed polyacrylamide (HPAM) is used as the polymer, which is injected in a sandstone core with brine. The produced fluids are analyzed afterwards, where its ion concentration, rheology, pH, and carbon content are measured. The results of the effluent analysis shows no change in viscosity compared to the injected polymer. There is however, a decrease in the divalent cations in the Low-salinity fluids, which can be explained by these cations getting stripped from the fluid at attaching to the rock surface. An increase in the effluent High-Salinity Brine is observed, which may be the cause of mechanical degradation, or by the influence of dissolved Ca2+ or Mg2+ cations due to leaching.