The storage of carbon dioxide is now regarded as a critical industrial application aimed at mitigating its accumulation in the atmosphere. Reservoirs and aquifers have been identified as viable alternative locations. This report seeks to examine the impact of sedimentological heterogeneity on the development and migration of CO2 plumes over time. The study uses the Roda Sandstone Formation as a case study, primarily due to the presence of carbonate-cemented layers within the Gilbert-delta lobes, which contribute to reservoir heterogeneity commonly observed in subsurface formations. The utilization of a sketch-based modeling approach was employed in constructing the geo-models represented by Rapid Reservoir Modeling (RRM) software since the Roda Sandstone is an exposed section in Isabena Valley in Spain. Furthermore, various realizations are constructed using different parameters of the cemented layers to comprehensively comprehend all potential scenarios. The aforementioned observations pertain to variations in the thickness and lateral continuity of the cemented layers. Additionally, dynamic modeling is also performed by injecting CO2 into the reservoir for 50 years. The simulator utilized for dynamic modeling is the Delft Advanced Research Terra Simulator (DARTS). The findings demonstrate that reservoirs with moderate sedimentological heterogeneity are actually better sites to store CO2 due to the capacity and effectiveness of the storage.

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.

The data assimilation process for geothermal reservoirs often relies on well data which primarily offers insights into the immediate vicinity of the borehole. However, integrating geophysical methods can provide valuable information beyond well proximity, possibly enhancing reservoir predictions. Electromagnetic methods can be sensitive to the decreasing conductivity from heat extraction in geothermal reservoirs. A scheme to incorporate electromagnetic data into a data assimilation process for geothermal reservoirs is presented and implemented in this study. First, an ensemble of prior models representing the reservoir uncertainty is used to determine the moments of the resulting temperature field using a forward geothermal simulation. Source and receiver locations are determined by maximizing the distance of the path through the expected temperature changes while ensuring that the source and receiver are not excessively distant. Subsequently, a conductivity model is implemented using an empirical relationship. The expected electric field response can then be simulated using an electromagnetic forward model. To assimilate the data, the Ensemble Smoother with the Multiple Data Assimilation (ES-MDA) method is employed. The findings demonstrate that the incorporation of electromagnetic data provides more information regarding the temperature field, which when combined with the localized data from the production well improves the temperature forecast accuracy of both the production well and the entire reservoir model.

Discontinuities have an important influence on the bulk behaviour of geomaterials. Discontinuities can be physical openings like fractures and joints, interfaces between different material types, or zones with different material behaviour like mortar or reinforcement material. Bulk material behaviour is often determined by the behaviour of the discontinuities by providing preferential pathways for flow or by acting as failure planes.
FEM simulations with continuum elements are typically not suitable for modelling discontinuities with no width, due to the inability to model discontinuous fields. One solution is to represent discontinuities using zero-thickness interface elements. Inserting zero-thickness interface elements allows for discretely modelling discontinuous behaviour between neighbouring continuum elements. The continuum elements are then used to represent the bulk behaviour and the zero-thickness interface elements discretely model the discontinuity.
A new constitutive law for zero-thickness interface elements that expands the cohesive zone model with friction is formulated in this thesis. The tangential stress response of the interface elements consists of a cohesive and frictional contribution. The cohesive component of the constitutive law is based on the Crisfield’s cohesive elasto-damage model, which is characterised by a linear elastic response to increased relative displacement, followed by degradation of the cohesive strength and stiffness. The elasto-plastic frictional component is based on the Dahl friction model and implemented in parallel to the cohesive component.
The implemented new constitutive law is verified in a large variety of loading conditions, including tangential loading, tangential loading with a reversion of loading direction and combinations of mixed-mode loading. The constitutive laws are validated based on shear box experiments performed on London clay where interface elements are used to model a predefined shearing plane.
The cohesive and frictional constitutive law can represent confinement-dependent tangential stress and residual stress at large relative displacements. These features, observed in the shear box experiments, could not be reproduced by the purely cohesive constitutive law. This new constitutive law can be used to better model discontinuities in geomaterials represented by zero-thickness interface elements.

Over the years, modelling frameworks have been proposed to describe and predict the degradation of municipal solid waste in landfills. These frameworks, however, fail to couple the kinetic solutions to the real-time equilibrium state of the system. Because of this, fundamental processes such as pH changes, NH4+ adsorption to the waste surface and changes to the fluid composition are often not (or inadequate) taken into account. In this study, we propose a degradation model that couples a kinetic solver to the chemical equilibrium software, ORCHESTRA. For this, a tool is developed that allows seamless operability between ORCHESTRA and the Python environment. The modelling framework is used to simulate the degradation of solid organic matter in a batch reactor following a simplified, but comprehensive, reaction network. Reaction rates are based on Monod kinetics that includes a wide variety of inhibition functions. The Freundlich equation is used to capture NH4+ adsorption to the waste surface. Results from various case studies show that the modelling framework is suitable for coupling real-time landfill chemistry to degradation kinetics. We found that NH₄⁺ concentrations play a dominant role in the presented model. While low NH₄⁺ concentrations limit biomass growth by substrate inhibition, high concentrations (>0.002 4
mol/L) affect the hydrolysis rate by toxicity inhibition. This translates to a model that is sensitive to a variety of input parameters such as the initial C/N ratio, the Kd (degree of adsorption) value and the initial organic fraction. A comparison with literature studies, however, implies that the model lacks fundamental processes such as gas and fluid transport or changes in volume and temperature. In addition to this, we discuss that the Freundlich isotherms may be inappropriate to capture adsorption in a coupled framework as no ion exchange is taken into account. Models that do so, such as the NICA-Donnan model, could improve the model results significantly.

Aquifer thermal energy storage (ATES) is an energy efficient technology to temporarily store groundwater of different temperatures in an aquifer. The basic idea behind ATES is to store thermal energy in warm and cold wells so that the energy can be used for heating and cooling of buildings in the next season. Design and planning of ATES systems requires numerical simulation tools such as SEA- WAT, COMSOL, and FEFLOW. COMSOL and FEFLOW are expensive commercial products. SEAWAT is a free computer program based on MODFLOW and MT3DMS. The flow field is modelled with the finite difference method while there are several methods to simulate the heat transport including the finite difference (FD) method and the total variation diminishing (TVD) method. OpenGeoSys (OGS) is an open-source alternative based on the finite element method which is able to simulate groundwater flow and heat transport processes and can potentially be used for design and planning of ATES systems. There are very few applications of OGS to simulate ATES systems. The main goal of this research is to assess the usability of OpenGeoSys in the simulation of ATES sys- tems. The numerical solutions of OGS and SEAWAT (both the TVD scheme and FD scheme) are compared to the analytical solutions for a single well that injects water with a constant flow rate of water and constant temperature. For a doublet with a cold well and a warm well, the OGS solution is compared to the SEAWAT solution for both a sin- gle cycle system and a multiple cycles system with constant flow rates and temperatures. Finally, a field case of a doublet with varying flow rates and injection temperatures is studied to compare the performance of OGS to SEAWAT. The main findings of this study are as follows. Both OGS and SEAWAT can reproduce the heat transport process of the analytical solutions for a single well injecting warm or cold water. There are some deviations between the temperature distributions computed by the numerical models and the analytical solutions which are primarily caused by nu- merical dispersion. The TVD scheme results in the smallest numerical dispersion while OGS shows slightly more numerical dispersion when applying the same number of cell- s/nodes. Numerical dispersion can be reduced by application of finer spatial resolution for the SEAWAT since the time step is adjusted automatically. For OGS, the time step must be reduced manually when the grid is refined. Both OGS and SEAWAT show energy balance errors smaller than 1%. Numerical dis- persion has an effect similar to physical dispersion so that the thermal radius increases when the numerical dispersion is larger. The interaction between the warm well and cold well of a doublet increases when the thermal radius increases, which may result in an increase of the energy balance error. According to the analytical solution for the model where the heat transport between the aquifer and aquitards is included, OGS shows the smallest overestimation of thermal energy that remains in the aquifer part compared to the two solution schemes of SEA- WAT. The vertical temperature distribution in aquitards simulated with OGS is closer to that of the analytical solution compared to SEAWAT. Both numerical dispersion and the overestimation of thermal energy in the aquifer have an influence on thermal recovery efficiency of an ATES system. Larger numerical dis- persion indicates a longer heat transport distance, resulting in more time needed for thermal energy to transport back to the wells during the extraction period. Similarly, the overestimation of the thermal energy in the aquifer provides more thermal energy dur- ing the extraction period. There are some overshoots/undershoots when simulating an ATES system with varying flow rates and injection temperatures by the TVD scheme. This can be eliminated by refining the spatial resolution. It is more complicated to simulate an ATES system with OGS than SEAWAT. The com- putational time is much longer for OGS compared with SEAWAT by a factor of around 10 for the same number of cells/nodes. Despite these drawbacks, OGS is suitable for the simulation of ATES systems as the simulated temperature distribution in both the aquifer and aquitards compares well to the analytical solution, and there are no prob- lems of overshoots/undershoots in the simulation of varying flow rates and injection temperatures.

The rising demand for clean energy has drawn the attention for more geological research to low enthalpy geothermal applications in the Netherlands. A multi-scale reservoir characterization is carried out with the aim to understand the geothermal reservoir potential of the Triassic Main Buntsandstein (RBM) in the Tilburg area. Seismic data, well logs and petrophysical data are used to evaluate the reservoir architecture, stratigraphy, and quality of the potential Main Buntsandstein geothermal aquifer. It was found that the study area is located within a horst- and graben system bounded by normal faults where the top boundary of the RBM is located at depths of 1900 – 2100 m for the horsts and 3300 – 3500 m for the grabens. The horsts and grabens range from circa 3000 to 4000 meters in width. Well log correlations and thickness maps at RBM scale suggest thicknesses of the Subgroup from ca. 160 to 220 meter. The thickness of the Main Buntsandstein generally decreases on the horsts and increases towards the grabens, suggesting higher temperatures of up to 100° C and thicker sand units in the grabens. Thickness generally decreases on the horsts and increases towards the graben suggesting faults were active at time of deposition and better geothermal potential in the grabens due to greater depths and thicker RBM unit. The core analysis of the study showed that the potential Main Buntsandstein reservoir is composed of a variation of sand- and mudstones interlayers, which were deposited on a large fluvial-fan system terminating in a playa-lake environment towards the basin center. Four different facies associations were distinguished within the cores of wells AND-06, KWK-01, SPC-01 and WWN-01-S2. Optimal reservoir connectivity is, according to the facies architecture model, expected in the Lower Volpriehausen and Detfurth Sandstone Members due to the presence of stacked amalgamated fluvial fan sandstone facies. It appeared that aquifer quality does not correlate with increasing depth or stratigraphic position, although the Volpriehausen- and Detfurth Claystone Members display significant poorer reservoir properties. These members, which can be correlated at well distance due to its widespread deposition as playa-lake sediments, are likely to act as a baffle to flow in the subsurface. Best reservoir potential, considering petrophysical measurements on porosity and permeability, is within the fluvial fan sandstones of all facies associations whereas the fine grained cross bedded sandstones show best reservoir quality of all encountered lithofacies. The data showed highly variable measurements where highest mean values for the porosity (11 %) and permeability (105 mD) are encountered in the Lower Detfurth Sandstone Member of well HVB-01. It turned out that northern located wells of Tilburg (AND-06, KWK-01, WWN-01-S2 and SPC-01) showed considerable poor reservoir potential with mean values of below 10% and 10 mD for the porosity and permeability. The southern wells, however, appear to have generally higher reservoir properties compared to the northern wells suggesting better geothermal potential in the area south of Tilburg.

For many decades, conventional gravitational separators have been the backbone of the fluid separation in the oil and gas industry. The stricter environment regulation for purification of the recycled water, together with a tighter profitable margin of the produced oil, requires more efficient and faster separators. Inline swirl separator uses centrifugal acceleration up to hundreds of gravitational accelerations to perform separation in a much faster time. However, its efficiency is still lower than the industry expectations. There are essential geometric parameters such as swirl intensity and the collector tube, and vital operating conditions such as flow-rate at the entrance and mass flow-rate at each exit that impact the dynamics behavior of swirl flow in the pipe. The dynamic behavior of the swirl flow determines the efficiency of the apparatus. Thus, the main objective is to understand the dynamics of the single-phase swirl flow in the pipe and determine an inline swirl separator that presents sufficient efficiency. The first part of the study focuses on a better understanding of the dynamic behavior of the swirl flow in a pipe. The second part utilizes the results from the first stage to determine an inline swirl separator that presents sufficient efficiency. The performed numerical study suggests that the dynamic behavior of swirl flows in a pipe is determined by the intensity of the swirl flow, which is quantified by the swirl number. The swirl intensity shapes the axial velocity profile at the core of the vortex. When the swirl number increases beyond a critical number, a columnar vortex appears, with a reverse flow along with the center of the entire tube. The swirl intensity decays along the wall of the pipe; the swirl intensity and the decay of it form the shape of the axial velocity profile. In case the disturbance of the flow results in a stagnation point at the vortex axis, it may develop a vortex breakdown. The vortex breakdown in high Reynolds numbers ( Reb > 100,000) is a function of the swirl number, and the instability at the vortex core increases by increasing the swirl intensity. Furthermore, the results show that the stability of the vortex is a function of the Reynolds number. Considerable reduction of the Reynolds number kicks in the effect of viscous forces, which stabilize the vortex core. Reynolds and swirl numbers determine the dynamic of the low Reynolds number but turbulent, swirl flow. Therefore, the industry needs to rely on Reynolds Averaged Navier-Stokes (RANS) simulations; Direct Numerical Simulation predictions obtained at much lower Reynolds numbers may not predict the occurrence of the vortex breakdown inside the pipe. These findings show that there are essential design considerations, which determine the efficiency of the swirl separator. Thus, a combination of the geometry parameters and the swirl flow characteristics should be considered to avoid the reverse flow zone and vortex breakdown inside the inline separator. One of the vital elements of the inline swirl separator is the collector tube. The study shows that the collector tube at the neutral flow split, with no bias of the mass flow-rate at each outlet, changes the velocity to the extent that he reverse flow zone for Sw=0.5 is eliminated. Pressure actuators can control the flow; therefore, controlling the flow split at both outlets. The numerical results show that an additional percentage of flow split enhances efficiency by eliminating the reverse flow zone for the higher swirl numbers. Additionally, the study reveals the counter effect of the extreme flow splits, which hinders the efficiency of the inline swirl separator. These optimal settings for the geometry of this research were found at swirl number 1.6 and flow split of 50%.

As implementation of deep geothermal energy projects in the Netherlands increases, reservoir simulation for these geothermal systems stands to play a key role in understanding how these systems will behave and how large scale projects can be optimised to save cost and reduce risk. In this thesis, an extensive simulation study has been conducted using a new Operator based linearisation simulator (DARTS) on a geological model of the Delft Sandstone Member within the West Netherlands Basin (a prolific geothermal reservoir). The first section of the study outlines the construction of a representative geological model of the Delft Sandstone in Petrel using core, well log and seismic data.
The model is quality checked by comparing derived model values with both values recorded in the literature and data from well tests. Following this, a sensitivity and uncertainty study was conducted which examines the effect of changing a wide range of model values and inputs on the thermal
performance of production wells. A well placement study was then implemented, examining how well configuration, orientation and distance can affect well performance. Finally, a considerable section of the thesis investigates the role of non-reservoir lithologies in geothermal reservoir simulation and how the heat transfer from these lithologies can be accounted for utilising multi-scale
upscaling. The findings of the uncertainty and sensitivity analysis suggest that the primary uncertainty for simulation in the Delft Sandstone is the porosity and intrinsically linked permeability, with the value and spatial distribution of these properties having the largest effect on thermal performance of wells (10’s of years difference in thermal breakthrough). From the well placement study, it was found that different well configurations performed variably according to local reservoir conditions (especially reservoir dip) and that optimum configuration should be decided on a case-by-case basis. It was also found that both well separation/interference and orientation have a key role in controlling the thermal productivity of wells. Finally, the section on non-reservoir lithologies finds that firstly, thermal recharge of injected water from these rocks can have a very large effect on thermal breakthrough time (10’s of years for low N/G reservoir) and must not be ignored in geothermal simulations and secondly,
of the three multi-scale upscaling methods implemented to more efficiently simulate conductive heat flux from the non-reservoir rocks, only multiple sub-region upscaling shows significant promise in terms of accurately accounting for heat flux and significantly reducing the number of grid cells. However, the quality of the solution for this method is still strongly linked to fluid flow rate, with higher rates resulting in better solutions.

The subsurface of Groningen gas field composed of several faults. The continuous production has been resulting in several micro-seismicity activities, particularly for the past decades. One of the reasons for the production-induced-seismicity is fault reactivation at depth. The fault that initially in the non-active state becomes active and starts slipping due to pore fluid extraction. The modelling of fault reactivation induced by production can be simulated by coupling of flow and geomechanics.

The project studies the coupling of flow and geomechanics for an idealistic subsurface model with fault. The flow occurs due to pore pressure depletion and is predicted by solving mass conservation. The corresponding deformation is estimated by momentum balance equation.

The observation will be limited to rock deformation that is quantified by effective stress and displacement on the fault due to a pressure change in the subsurface. The simulation is performed using Stanford's Automatic Differentiation General Purpose Reservoir Simulator (ADGPRS).

In the proposed model, the flow equation is discretised using finite volume method, and poromechanics is discretised by finite-element Galerkin's approach. Both problems share the same grid model, and there is no error associated with the information exchange. The coupled problem is being solved fully implicitly where flow and mechanics formulation are solved simultaneously.

The case study for the simulation is a simplified Groningen subsurface model with a fault zone. The impact of variability in production dynamic on fault reactivation is studied. The variations in production rate and production strategy are applied in different formation configurations. It is found that the correlation between the production rates and the stress state in the subsurface depends on the formation offset. However, the stress field does not depend on continuity of the production scheme. Several aspects including the presence of Gas-Water contact in the model was studied in this project as well.

A rock fracture is a mechanical break or discontinuity that separates a rock body into two or more parts. The continuity or cohesion of the rock body is lost across a fracture. Fractures are formed in response to stress on a rock. A rock breaks and forms a fracture when the applied stress reaches the rock strength. Vertical fractures improve connectivity between multiple layers, and can aid the production of geothermal and petroleum reservoirs.
The heterogeneity of layered reservoirs leads to significant variation in mechanical properties, which in turn influence fracture nucleation, fracture growth and fracture geometry. This variation in rock mechanical properties, combined with layer thickness, is called mechanical stratigraphy. Natural fractures are subject to controls imposed by mechanical stratigraphy. Focusing on the mechanisms that control natural fracture development can improve fracture characterization. As rock strength is an important part of mechanical stratigraphy, the term mechanical contrast is introduced to examine the effect of contrasts in rock strength of adjacent layers.

This study examines the effect of the mechanical contrast and confining pressure on fracture behaviour in layered rocks in the laboratory. The focus of this study is threefold, it examines the effect of mechanical contrast and confining pressure on fracture propagation, fracture orientation and fracture aperture in layered rocks.
Unconfined and confined compressive strength tests have been performed on layered samples with varying mechanical contrasts at different confining pressures. A total of 169 tests have been performed which include confined and unconfined compressive strength tests on layered and monophase samples and brazilian tensile strength tests and velocity measurements on monophase samples.

The results show that fractures initiate in the weakest layer and propagate through the layer interface or are contained within the weakest layer. Unconfined compressive strength tests showed that differences in rock strength do not always act as a containment barrier.
The combination of mechanical contrast and confining pressure does control the containment of fractures within a layer. Lower horizontal compressive stresses are required to contain fractures when the mechanical contrast increases.
Mechanical contrast does not seem to influence fracture aperture. Confining pressure however greatly influences fracture aperture as it limits the ability of fractures to dilate.
Results show that fracture orientation is controlled by mechanical contrast. Fractures refract at layer interfaces when the mechanical contrast is sufficiently high. Confining pressure does not seem to affect the refraction of fractures.

The experimental results can improve the understanding of fracture containment, fracture aperture and fracture orientation in layered rocks at subsurface conditions. The mechanical contrast of the layered rocks, combined with the stress conditions need to be considered when characterizing subsurface fractures.
Vertical connectivity between layers is of importance when predicting fluid flow through reservoirs. As frac tures often serve as preferential fluid flow paths, correctly interpreting fracture characteristics is important for successful development of layered reservoirs.

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.

A pilot for a large scale, fully integrated chain of CO2 capture, transport and storage (CCS) has been initiated in the port of Rotterdam. The initiative aims to demonstrate the technical and economic feasibility of CCS and show that it can be deployed on a large scale for power plants and energy-intensive industries that emit large volumes of CO2. The partially-depleted Q16-Maas gas condensate field could potentially be used to permanently store the captured greenhouse gas (CO2). The case study shows the potential that this field has for CO2 storage and also examines other options for life-cycle extension. The case study is based on macroscopic scale reservoir behaviour and simulated in the fully compositional simulator, Eclipse 300. Gas reservoirs have a proven track record for safely trapping gaseous phases in the subsurface over long geological timescales. As long as initial reservoir conditions, mainly pressure (=296,5 bar), are not exceeded, CO2 in supercritical phase should be safely stored. According to literature, with increasing storage time, the CO2 is even trapped more securely, although this process may take hundreds to thousands of years.
The results of the case study show that approximately 1.1 million tonnes of pure CO2 can be stored in Q16-Maas field. By side-tracking the original well and producing the attic gas in the reservoir, 160 million cubic meters of additional gas can be recovered, along with condensate. If the side-tracked well is then converted to a CO2-injection well, the CO2 storage capacity is increased to 1.4 million tonnes. This injectable CO2 volume is less than the two million tonnes originally estimated and this is due to the influx of water from a strong aquifer that has partially filled the void left by depleting the gas field.
The possibility of enhanced gas and condensate recovery using CO2 has also been investigated in this case study, as the use of CO2 for miscible floods in hydrocarbon reservoirs has been proven and used successfully as a tertiary recovery method. The reservoir simulation of the Q16-Maas field shows that there is no additional hydrocarbon recovery by CO2 flooding. Sidetracking to and producing from an updip location in the reservoir is equally as productive. The reason for this is attributed to presence of a strong water aquifer, together with the varying reservoir quality and thickness prevents the successful application of CO2 enhanced hydrocarbon recovery. The total cost of transport and storage (OPEX and CAPEX) was estimated to be 71.5 million euro. Assuming CO2 storage volume of 1.4 million tonnes, the project would need to receive roughly 50 euro/tonne in order to breakeven for storing and transporting the CO2, the capturing is not included.