Carbon Capture and Storage (CCS) is an effective method for reducing CO2 emissions by permanently storing captured CO2 underground. Depleted oil and gas fields are promising CCS targets due to their well-characterised nature. However, injecting high-pressure CO2 into low-pressure reservoirs can lead to hydrate formation due to Joule-Thomson (JT) cooling and phase changing during CO2 injection, potentially reducing injectivity.

Since hydrate formation mainly occurs in the near-wellbore, it is essential to assess the influence of mud filtrate and formation damage on CO2 hydrate formation. Oil-based mud (OBM) can invade the formation, making its filtrate the first material to interact with injected CO2. This study addressed the impact of the synthetic OBM filtrate, represented by dodecane, CaCl2-15wt%, and W/O emulsion, on CO2 hydrate formation in micromodel experiments, focusing on hydrate morphology and saturation.

Results show that the interaction between CO2 and synthetic OBM filtrate can induce CO2 hydrate formation under certain pressure-temperature conditions. Instability of the OBM filtrate emulsion during low-temperature CO2 injection, followed by water droplet coalescence, increases the water-CO2 contact area, thereby promoting hydrate formation. Experiments involving oil and W/O emulsion revealed a distinct hydrate morphology, with hydrates present not only at the CO2-water interface but also within the CO2 flow pathways.

The study also highlights that high salinity CaCl2–15wt% acts as a CO2 hydrate inhibitor. In the presence of synthetic OBM filtrate, hydrate saturation is higher than in the system containing only CaCl2–15wt% or a combination of CaCl2–15wt% and dodecane, likely due to enhanced water–CO2 contact from droplet coalescence in the W/O emulsion.

Furthermore, the impact of formation damage on near-wellbore pressure and temperature relative to the hydrate stability zone (HSZ) was examined. Mud filtrate can reduce permeability, while hydrate formation can exacerbate this damage. Such changes alter local thermodynamic conditions, requiring a coupled wellbore–reservoir simulation to capture the dynamic interactions.

Simulation results indicate that greater formation damage may reduce the risk of hydrate formation by increasing the temperature and pressure in the near-wellbore. If hydrate occurs and leads to additional permeability impairment, it could result in increased bottom-hole temperatures. Such a temperature rise may help dissociate the hydrates, provided the increase is sufficient to shift the system out of the HSZ. Formation damage due to mud filtrate (30-60% permeability reduction) typically keeps pressure and temperature conditions within the HSZ. Additional damage due to hydrate formation (80-90% permeability reduction) significantly increases bottom-hole pressure (BHP) and bottom-hole temperature (BHT), thus shifting the pressure and temperature conditions outside the HSZ. Notable changes in both BHP and BHT occur when the radius of the damaged zone increases from 0 to approximately 0.5 meters. Beyond this threshold, further increases in damaged radius result in only marginal BHP and BHT changes. ... Read more

Considering the global effort to combat climate change, a promising solution in reducing CO2 emissions is the Carbon Capture and Storage (CCS) application. Such projects aim to store CO2 inside subsurface geological formations. Depleted gas reservoirs are considered as one of the best options for CCS projects to take place. However, one of the main challenges that can be encountered is the impairment of CO2 injectivity near the well caused by the formation of CO2 hydrates which further result in porosity and permeability reduction of the reservoir rock. While the thermodynamic boundaries have been extensively studied, the kinetics of CO2 hydrates inside porous media remain less investigated. So, this study investigates the kinetic behavior of CO2 hydrate during both formation and dissociation within Bentheimer sandstone core samples under varying thermal conditions, aiming to get a better understanding of how thermal delivery either during hydrate formation with cooling or during hydrate dissociation with heating can affect the hydrates. On top of that, the effect of subcooling as a driving force is also investigated. During the experimental work of the study multiple core flood experiments with constant CO2 injection (dynamic conditions) were conducted, applying different cooling and heating methods, with a specific focus on subcooling and the rates of thermal stimulation. A combination of pressure and temperature monitoring, computed tomography (CT) imaging and permeability measurements were employed to evaluate hydrate behavior in real time. The results showed that subcooling is a dominant driving force and higher degrees of subcooling resulted in shorter induction times, increased hydrate saturation, and greater permeability reductions. Very fast cooling rates led to faster hydrate formation which further resulted in greater permeability losses. Conversely, constant higher heating rates caused more hydrate dissociation and faster permeability recovery. A temperature threshold below the hydrate equilibrium temperature was consistently identified, where significant dissociation occurred, indicating that the porous medium inhibits hydrate formation and promotes hydrate dissociation. Hydrates formed under non-constant cooling dissociated more easily, while slow constant cooling resulted in hydrates that were more resistant. Despite full dissociation across all experiments a residual permeability loss of 8-10 % was observed. Additionally, hydrates formed under constant cooling methods displayed different permeability behavior compared to those formed under non-constant cooling methods, indicating a potential difference in pore-scale hydrate distribution. This thesis will delve into how temperature and subcooling can impact the kinetics of CO2 hydrates formation and dissociation within the context of CCS in depleted gas reservoirs. ... Read more

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. ... Read more

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.
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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. ... Read more

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.
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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.
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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.
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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.
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Miscible gas injection has been widely used worldwide to improve oil recovery. However, problems such as viscous fingering and gravity override undermine its success on a large scale. Foaming of the injected gas mitigates these problems by reducing the mobility of the gas.

Past studies using an ionic surfactant to foam CO2 in the presence of decane discovered the presence of three distinct regions based on the fraction of CO2 in the CO2-decane mixture namely; CO2-rich floods where the apparent viscosity increased with the increase in the CO2 molar fraction, decane-rich floods where the apparent viscosity decreased with the increase in the CO2 molar fraction and floods with intermediate CO2 molar fraction where the apparent viscosity was independent of the CO2 molar fraction in the CO2-decane mixture. The foam quality scans showed that the CO2-rich floods and decane-rich floods exhibited both low and high-quality regimes while the floods with intermediate CO2 molar fractions lacked a high-quality regime [1].This behaviour was not fully understood.

The effect of the surfactant type on the observed behaviour has been studied in this thesis by using a non-ionic surfactant in the foam quality scans. The results show the presence of the three distinct regions as observed in the previous study with an ionic surfactant. However, this study shows that the quality scans of all the CO2-decane molar compositions exhibit both the high and low-quality regimes. This study also shows that both the low and high-quality regimes are present at high flow rates. In addition, the flow behaviour is shear-thinning in nature and can be modelled by the power law.

Furthermore, the transient generation of CO2 foam in the presence of decane at different CO2-decane molar compositions has been investigated. The results show that the generation of CO2 foam in the presence of decane depends on the injected amount of CO2-decane mixture and is independent of the CO2-decane molar composition and quality.

Lastly, the effect of permeability on transient foam generation has been tested in low permeability cores and has been compared to foam generation in high permeability cores. The results show that foam generation occurs earlier in low permeability cores. In addition, the low permeability cores are susceptible to damage and blockage especially at high injection rates.

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Exergy investment in producing hydrocarbons is a relatively small fraction of the energy of the oil produced; yet it can reduce energy consumption in the order of percentages. In areas of high insolation or high wind speed, it can be considered that part of the exergy required for these purposes can be retrieved from sustainable energy sources. This idea is expected to be more important when applying enhanced oil recovery. As an example we use solvent (Dimethyl Ether - DME) enhanced water drive recovery. DME is a chemical solvent that has proven to be an efficient oil recovery agent. The recovered DME and oil are both considered products. The main invested exergy considered are the circulation costs of the fluids, separation/retrieval costs and the manufacturing costs of DME – it is assumed that DME is manufactured from natural gas using the single step direct method.
To improve the insight in the production process we develop a simple model of DME enriched brine injection in a 1-D reservoir. The model shows that about 92% of the oil in place is recovered using DME, which includes about 30% incremental production after water flooding. Moreover, 100% of the DME injected is recovered.
For the production /retrieval costs, we use a data set from the literature. The data set gives us the amount of DME /water injected and the amount of DME /oil/water produced. Moreover it gives the pressure drop, which allows us to calculate the power required for circulation of the fluids. Using these data, the exergy recovery factor (ExRF), which is defined as the exergy of the resources minus the exergy invested divided by the exergy of the resources produced (oil and DME) is calculated. It is observed that the ExRF initially increases with time before it declines and becomes negative. The time at which the ExRF becomes zero is called the exergy zero time. The result shows a negative exergy at the beginning of the DME enhanced water flood (DEW) process. As the incremental oil produced increases due to the presence of DME, and as more DME is back produced, which leads to less manufacturing of DME, the ExRF becomes positive. For DME enhanced recovery the initial area below exergy zero time plus the area above the exergy zero time is positive. Cumulatively, the result shows that at the end of the project, about 71% of the exergy is recovered.
The exergy analysis helps us to identify the various components that contribute the most to the exergy loss (~29%). DME manufacturing is found to be the most important contributor to the exergy loss, contributing ~80% (cumulative) to the total invested exergy. It shows that reducing the exergy of manufacturing DME increases the ExRF. The amount of DME lost in the reservoir is shown to also have an effect on the ExRF (not as much as the exergy of manufacturing DME), as it affects the utilization factor of DME. The utilization factor is the ratio of the oil produced (bbls) and the mass of DME injected. If DME is lost more DME must be injected without any increase in oil recovery and thus, DME loss reduces the ExRF.
CO2 hydrogenation is chosen as one of the innovative ways of producing DME from renewable sources. The method utilizes CO2 captured from burning the oil produced from the field in power plants and uses solar PV (photovoltaic) as the source of energy to produce H2 from water electrolysis
The results show that the CO2 captured from the power plant can be used to produce more DME than what is needed in the field. The excess DME can be reinjected or used for other purposes such as electricity generation, methanol production or for other uses e.g. as transportation fuel. It is also found that using CO2 hydrogenation has the potential to reduce greenhouse gas emissions by about 82% compared to using natural gas for DME production, which means the method is cleaner and more sustainable. ... Read more