Revealing an optimal geothermal development strategy attempt with long-term sustainability (upcoming 100 years) based on a real 3D model derived from seismic data is considered one of the main contributions of this research study. The heat extraction and thermal recharge of the reservoir must be in balance to extend the productive lifetime of the Koekoekspolder field system. Based on the best results obtained among different unconventional thermal development approaches, the best locations for the new production wells or extra geothermal doublets as well as the timing, injection temperatures, and rate at which the doublets operate are determined. The best strategy to develop the Koekoekspolder field can be achieved by several steps such as understanding the reservoir properties such as the sedimentary facies, porosity, and permeability distribution by analyzing the literature studies and the static model that simulates the Slochteren formation using Petrel software based on the seismic and log data available followed by a dynamic model that mimics the flow of the hot aquifer inside the reservoir using Eclipse 300 software. Both static and dynamic models must be calibrated by the accessible production data to decrease inaccuracy. The thermal boundaries that are taken into consideration for the koekoekspolder field are not mere confining layers. The workflow of this research study ensures a high degree of realism in terms of the input data and output information of the thermal model of the Koekoekspolder field. The best locations for the new production wells or extra geothermal doublets are determined based on the best simulation results obtained from this research study which fulfill the future energy demand increment. The procedures used in this research study give clear guidance on how the Koekoekspolder field or any other geothermal field can be sustainably developed using a robust history-matched model that has reliable predictions. The low-enthalpy deep geothermal system of the koekoekspolder field is optimized and developed using different types and scenarios of operational strategies for doublets which allow adequate periods for operational thermal recharge. This study takes into consideration different thermal parameters that are not common to achieve enhanced predictions. Moreover, it illustrates the importance and benefits of considering reservoir boundary conditions. Finding suitable sustainable geothermal field development for the Koekoekspolder field can be achieved by new well-studied techniques that can ensure adequate thermal recharge periods. The results of this research study show that the energy demand can be fulfilled with low investment costs to increase the profit of the field owner. Long-term (around 1 century) sustainable development of geothermal fields such as Koekoekspolder and the new technology in this research study can partially contribute to achieving the geothermal master plan objectives in the Netherlands as well as enhancing low and high-enthalpy geothermal field development worldwide.

In this thesis two problems in network transport are analyzed.

The first problem concerns flow through static foam in artificial fractures. The objective is to determine whether the assumption of Li et al. (2021), that capillary pressure is uniform in the region of interest, with static foam in an artificial fracture, is justified. This would be the case if water can flow through Plateau borders at a rate that is quick enough for pressure differences to dissipate rapidly. Images of foam in the fractures are turned into networks of slits that are scaled down to flow through Plateau borders in foam. The results of this show that the capillary pressure can be assumed to be uniform.

The second problem concerns steady-state two-phase flow in microfluidic devices. The objective is to determine whether two phases can simultaneously flow at comparable fractional flows through a microfluidic device without alternating pore occupancy. This would be the case if the total mobility values of both phases are similar. To find the relative permeability values, a microfluidic device is simulated consisting of interface shapes based on the findings of Cox et al. (2022), arranged in a network according to bond percolation theory. The results show that it is unlikely that two phases with similar viscosity values can maintain steady-state flow at comparable fractional flows, and impossible if the viscosity ratio is that of gas and water. This implies that flow experiments done using microfluidic devices reflect the high-capillary-number flow regime where flow paths fluctuate in the pore network.

The United Nations’ Paris Agreement forces nations and industries to transition from conventional hydrocarbon-based energy sources to more sustainable and less-emitting alternatives such as geothermal energy. Geothermal doublets are used to provide a source of green heat to greenhouses and residential buildings. In industry, reservoir simulators are used to make predictions about the energy production and thermal lifetime of such a geothermal project; however they can be computational expensive. Upscaling approximates the expensive fine-grid simulation and reduces the necessary computational power, but is by definition not mathematically exact. This thesis tests a newly derived thermal dispersion-based upscaling method, referred to as Taylor-based upscaling, and compares it to conventional arithmetic upscaling and a reference fine-grid simulation. The upscaling methods are applied on reservoir descriptions from the Margretheholm-1A and the HON-GT-01 reservoirs, and simulations are done using Delft Advanced Research Terra Simulator (DARTS). The reservoirs are modelled as 2D layer-cake models in the form of a geothermal doublet with a fine longitudinal resolution, 1000 grid blocks between injector and producer, to minimize numerical dispersion. The results are presented as 2D-temperature profiles and breakthrough-curves. The deviations are quantified in the form of L2-norm calculations and by comparing the amount of days it takes for each upscaling method to reach a 1◦C or 5◦C drop in production temperature. The results show that arithmetic upscaling underestimates the spreading of the cold-temperature front leading to later breakthrough, whereas Taylor-based upscaling overestimates this spreading. For the Margretheholm-1A reservoir Taylor-based upscaling mimics the fine-grid reference simulation better compared to arithmetic upscaling, whereas arithmetic averaging performs better for the HON-GT-01 reservoir. Increasing the vertical thermal conductivity (kz ) leads to Taylor-based upscaling coming closer to the fine-grid reference simulation; however different reservoir descriptions require a different kz adjustment. In conclusion, the Taylor-based upscaling method does not outperform conventional arithmetic upscaling for all reservoir descriptions. Also, no universal rule was found for increasing the kz -value to improve the Taylor-based upscaling method.

The goal of this study is to test out the accuracy of the upscaling approach (Jinyu Tang, 2021) for a geothermal doublet. This approach tries to simulate the physical thermal dispersion. When modeling in a geothermal reservoir it would be easy if a lot of layers can be upscaled. However, when doing upscaling one can not just take an average of the layer properties. This results in a very inaccurate representation of reality. That is where the upscaling comes in. First, some other points need to be considered. The reservoir is simulated in DARTS (Wang, Voskov, Khait, & Bruhn, 2020). This simulator uses numerical methods to model the reservoir. Before starting on modeling geothermal reservoirs first a 1D case is evaluated to check for numerical dispersion that comes into play. With that evaluation done the 2D cases were simulated. The full reservoir has 91 layers, these can be upscaled into 9 layers eventually. To start building up to that scenario first 2 other scenarios are evaluated. First, an upscaled section of the first block of upscaled layers is evaluated. This was originally 10 layers and now upscaled to one layer. This one layer was first simulated in a one grid simulation and then a single grid simulation. These results are compared to a simulation of the original layer properties and a simulation of an arithmetic average of the reservoir properties. This is also done on a second scenario with 2 upscaled groups and eventually the full 9 layer reservoir (originally 91 layers). With these scenarios evaluated the upscaling shows to give a better simulation of the reservoir compared to using an average for the layer properties. This is all compared with a simulation of the original layer properties.

This study is part of a larger effort to evaluate the use of microfluidics to represent foam generation and flow in geological porous media (Rossen, 2008). Specifically whether it is possible to have flow in a microfluidic device without fluctuating occupancy of pores and pore throats. Although there is no foam created during the study, three of the main foam generation mechanisms are discussed. The 2D network consists of a 32x32 square lattice of cylindrical pillars, where all the pillars are surrounded by at the top and bottom by a liquid film that constricts the gas flow. The pores and pore throats are filled with gas or water. The gas flow paths are gas filled pores connected with gas filled pore throats. The water flow paths are pillars connected with water filled pores or pore throats. Liquid/gas bridges are necessary for the two phases to flow simultaneously through the network. An equivalent conductance for the gas networks is obtained by Hadjisotiriou (2020). But for that value to have any relation with that of the water network, the gas and water flow should be simulated within shapes that fit into one another under the same conditions. Because the paths in the network could have countless different variations, these paths are broken up into the smallest repeated segments. Then the total resistance of a path is obtained from a combination of these segments. Two unique segments are identified for the gas paths and four for the water paths. The segments are created in COMSOL™. A conductance value is obtained for each segment. With these values it is possible to calculate the total conductance for both the gas and water networks. The result is a fraction of water flow relative to gas flow of around 0.015. This means that only a small amount of water flow can be sustained by the network without fluctuating the occupancy of pores and pore throats. This makes it hard to explore foam generation in a microfluid device. It also means that two-phase flow in a microfluidic device is not representative of that in 3D geological porous media, except for in some exceptional circumstances.

Foams are used in reservoir engineering for enhanced oil recovery, CO2 sequestration and environmental remediation of aquifers and soils. One of the main mechanisms for foam generation at steady state is Roof snap-off. In some cases, mechanistic models of Roof snap off, based on observations from 2D micromodels are used for reservoir simulation. The main problem with these experiments is in their 2D nature. Two-phase flow within a 2D medium requires that the fluids paths cross and compete for pore occupancy. This virtually ensures fluctuating pore occupancy and therefore puts into question the applicability of 2D mechanistic models for steady state foam generation in 3D media. Two-phase flow in a micromodel is analyzed with a lattice percolation model in order to determine under what conditions steady two-phase flow can be achieved. The gas network is established with bond percolation and liquid is allowed to flow across the sample with the help of liquid bridges. These liquid bridges enable the liquid to cross gas-occupied pore throats without snap-off. The calculated attribute for the gas and liquid networks is equivalent resistance, ΔP/Q. For this a new unit for hydraulic resistivity was used and is equal to the fluid viscosity divided by the pore radius to the third power, H = μ/R3. The equivalent resistance of the gas and liquid networks are found by applying rules from linear circuits of electrical resistances. Solutions for the equivalent resistivity of the gas network are calculated with the node elimination method and Kirchhoff’s solution for a random network of resistances. The liquid network’s conductivity is calculated as the sum of path resistances in parallel and is a theoretical maximum. The gas and liquid conductivity of nine pre-existing 16x16 networks from Holstvoogd(2020) are reevaluated and, in addition, twelve new samples of size 32x32 are evaluated. Functionally, the model’s behavior is as follows: gas conductivity is inversely proportional and liquid conductivity is proportional to the occupation threshold. It is found that the gas conductivity is a function of tortuosity and number of parallel flow loops. Conductivity decreases with increased tortuosity and increases with number of parallel flow paths. The ratio of liquid and gas conductivity for the twelve 32x32 models is calculated. When adjusted for gas viscosities of supercritical CO2 and Nitrogen gas it is found that it is in the order of 10-3 to 10-4. Therefore, it has been determined that it is practically impossible to achieve steady two-phase flow without fluctuating pore occupancy.

This paper investigates surfactant flooding using a microfluidic device. Its purpose is to validate the results obtained in recent core experiments reported by Janssen et al. (2019) and provide mechanistic interpretation. In these experiments authors injected a surfactant slug into sandstone cores, initially brought to residual oil saturation. Low oil/water IFT leads to oil mobilization and the formation of emulsions. Furthermore, authors found that oil is more effectively mobilized when the injected surfactant is at optimum salinity. In this study the following experiments are subsequently conducted in a microfluidic device to validate this optimum surfactant slug: primary drainage, waterflooding and surfactant flooding. In case of the surfactant flooding experiment, the micro-emulsion formation was observed at 1.5 PV and 1.25 PV for the under-optimum and optimum conditions respectively. In both conditions, an increased oil mobilization was obtained, compared to the waterflooding experiment. However, the optimum condition, with a slug salinity of 2.0 wt% NaCl outperformed the under-optimum condition with a slug salinity of 0.4 wt% NaCl in terms of oil recovery. The increased salinity in case of the optimum condition results in an lower IFT compared to the under-optimum condition, which in turn results in an higher capillary number. The obtained results indicate a dependency between the capillary number and the amount of oil droplets. The optimum capillary number can be found at the lowest oil saturation with the largest amount of droplets. Based on the results obtained from the conducted experiments on this microfluidic device, upscaling is considered to be a viable and educated recommendation.

Steady multiphase flow in two-dimensional (2D) porous media has not been established without the continuous fluctuation in pore occupancy. Cox (2019) proves the ability of liquid to bridge a gas-filled pore throat that is narrow and deeply etched, allowing liquid and gas to flow simultaneously. In this investigation, a pore network study was done to discuss the feasibility of steady two-phase flow given the possibility of liquid bridging. Hypothetical percolating gas networks near the percolation threshold were made using Excel and MATLAB to highlight how each established phase can progress through a 2D square lattice. The percolating network describes the gas phase after it has established continuous flow through a water saturated medium. It was found that flow for both phases is easiest near the percolation threshold, where water progresses through a set of isolated clusters and gas has one major cluster that spans the entire lattice. It is predicted that liquid bridging is most problematic near or in the primary gas backbone due to lamellae mobilization. For a larger lattice, it was found that there is more distance between the primary gas backbone and the main water path. In contrast, the possibility of lamellae division occurring due to pressure differences within the lattice is highlighted.

Surfactant-Alternating-Gas (SAG) is a popular enhanced oil recovery method that utilizes foam to decrease gas mobility and subsequently improve reservoir sweep efficiency. SAG is known to have many benefits, such as mitigating corrosion effects and increasing gas injectivity. Despite this, liquid injectivity is typically very poor during the SAG process. Currently, there is not a consistent model for liquid injectivity during SAG. However, Gong et al. recently conducted core-flood experiments to gain clarity on how gas and liquid injectivity are affected during SAG in near-wellbore conditions. Gong et al. determined that gas and liquid injectivity are represented by the propagation of multiple banks. For gas injectivity, there are two banks: the collapsed-foam bank and the foam bank. For liquid injectivity, there are three banks: the collapsed-foam bank, the gas dissolution bank and the liquid-fingering bank.
Conventional foam simulators, such as CMG’s STARS, use the Peaceman equation to obtain an estimate for well pressure as well as liquid and gas injectivity. Gong et al. came to the conclusion that conventional foam simulators do not take the propagation of the collapsed-foam bank into account. Thus, Gong et al.’s results indicate that the Peaceman equation greatly underestimates gas and liquid injectivity during SAG in a 100 by 100 meter grid block. Subsequently, this paper aims to determine how refining the 100 by 100 meter grid block will alter well pressure and liquid and gas injectivity, especially in the near-wellbore region.
We used CMG’s STARS, a conventional foam simulator, to test the impact of grid refinement on injectivity and well block pressure. Our grid set-ups include a base grid of 5x5 equal blocks and two refined grid cases, in which the center grid blocks are partitioned into 9 and 25 equal block pieces. Our results indicate that as we refine the grid, the dimensionless pressure drops occur quicker and the magnitude of pressure decreases. When compared to the base grid, the pressure drops of the refined grids were discovered to be approximately 9 and 25 times faster for the 3x3 center grid case and the 5x5 center grid case respectively. Additionally, we observed additional dimensionless pressure peaks in the refined cases, which can be explained by a drop in relative mobility when the foam reaches a new grid block.
Although our foam parameters were based on Gong et al.’s foam scan, our foam parameters are not exactly the same as the parameters listed in Gong et al.’s paper because we did not include foam shear-thinning properties. In order to build on this paper’s research, future research should look into comparing our STAR’s results to the fractional-flow theory. Additionally, future models and research should look into reducing the simulation’s time step in order to increase the number of iterations calculated by the simulator, especially around the region in which the pressure drop occurs. Lastly, it would also be important to look into finding the best method to represent the well block pressure for a refined grid case.

Foam has unique microstructure in pore networks and reduces gas mobility significantly, which improves considerably the sweep efficiency of gas injection. Foam injection is thus regarded as a promising enhanced oil recovery (EOR) technology. One key to success of foam EOR is foam stability in presence of oil. This thesis seeks to understand fundamentally both steady-state and transient foam flow with oil in porous media through theoretical analysis and coreflood measurements. A quantitative modeling study is conducted to illustrate how the two algorithms ("wet-foam" model and "dry-out" model) represent the effect of oil on foam. Experimental observations evidently show that the two foam regimes without oil also apply to foam with oil, i.e. high- and low-quality regimes depending on foam quality. Oil affects both regimes with a stronger effect on the high-quality regime. Model fitting to data shows that currently applied implicit-texture (IT) foam models are suitable to represent foam flow with oil; both wet-foam model and dry-out model are needed to describe the effect of the oil on the two foam regimes. Three-phase fractional-flow theory together with the wave curve method (WCM) is applied to understand foam displacements with oil. Theoretical solutions suggest foam displacement cannot bank up an oil bank with oil saturation greater than an upper limit for stable foam. A critical phenomenon, i.e. that some injection conditions correspond to more than one possible foam states as predicted by the IT model, has been analyzed with fractional-flow theory and the WCM. We show how to determine the unique displacing state; the choice of the displacing state depends on initial state. Fundamentally, a boundary curve in ternary saturation space is defined that captures the nature of the dependence of the displacement on initial state. In addition, a new capillary number definition for micromodels is derived from a force balance on a ganglion trapped by capillarity. The definition in particular accounts for the impact of pore geometry and its validity is verified using two-phase flow data in micromodels. Based on current findings, some open questions concerning foam-oil interactions in porous media are defined and summarized at the end of this thesis.@en

Despite recent drop in the growth of global oil demand, the trend is expected to gradually pick up and continue increasing. Industrial and transportation sectors are still considered the highest consumers of oil. The petrochemicals sector’s demand for oil is increasing sharply and expected to continue in that fashion for the upcoming years. As oil fields age and mature, extraction of oil via primary and secondary techniques becomes, to an extent, inefficient. That encourages more research and development in enhance oil recovery (EOR) methods. In EOR, the aim is to either change a physical or chemical property of reservoir fluid in order to improve the oil recovery factor. The techniques can be categorized as thermal, physical, chemical or gaseous. In this experimental study, the lessons learned from gas flooding methods and surfactant flooding methods are taken into account in order to come up with a novel Foam-Assisted Chemical Flooding (FACF) procedure that aims to enhance the oil recovery factor to its maximum. In this approach, a surfactant slug solution is injected into a core at residual oil after water flooding conditions to mobilize trapped oil by capillary pressure. Then, a surfactant drive solution is co-injected with N2 for foam generation to serve as mobility buffer displacing the accumulated mobilized oil. The experimental study is performed under reservoir conditions of 90 ±1oC temperature and 20 bar of back pressure. In this study, surfactant stability is tested in synthetic formation brine. Then, phase behaviour tests are conducted to identify the capability of the surfactant to reduce o/w interfacial tension (IFT) to ultra-low values. The resulting solutions are categorized into their associated Winsor Types and classified based on salinity as under-optimum, optimum and over-optimum. A final surfactant slug solution is formulated based on these tests. Afterwards, bulk foam tests are performed in absence and presence of crude oil to test surfactant foaming ability and the resulting from stability and strength. Core-flood experiments are carried out to assess the possibility of generating foam in porous media in absence of crude oil and at residual oil to waterflooding. Full EOR FACF experiments are conducted, two at under-optimum and two at optimum salinity conditions. Two FACF experiments are performed with the assistance of medical CT scanner. In one FACF experiment, the foam is pre-generated utilizing a mixing tee and then injected into the Bentheimer sandstone. The study reported here showed that surfactants are not stable in synthetic seawater injection brine, as it tends to form complexes in presence of divalent ions, and subsequently generate precipitations. Stability was achieved by removing the divalent ions from the synthetic brine. In addition, phase behaviour study yielded that surfactant (A) is a better o/w IFT reduction agent than surfactant (B). A distinct layer of micro-emulsion was observed in excess of water and oil phases. On the other hand, surfactant (B) displayed better foaming abilities than surfactant (A) in absence of crude oil. Using surfactant (B), foam was generated in multiple qualities in a Bentheimer sandstone core-flood experiments in absence of crude oil. The critical foam gas fraction was found to be 75%. However, attempts to generate foam in porous media at residual oil to water flooding conditions were not successful. In three FACF core-flooding experiments, weak and unstable foam was generated during the surfactant drive co-injection phase. Whereas, in the last FACF experiment where a mixing tee was utilized, pressure drop and gas breakthrough data show that stable foam was generated. The CT images from two FACF experiments, one at optimum and the other at under-optimum salinity conditions displayed unstable water front in waterflooding phase, and unfavourable mobility conditions, during the surfactant slug injection. However, the effect of salinity conditions was seen in the different oil bank shapes in both experiments. The one at under-optimum salinity condition showed more unstable front. The study reported here showed that the FACF technology yields improving oil recovery of 70±5%, 77±5% and 73±5% for the FACF experiments where it was very challenging to generate foam in-situ and reached up to 80±5% of oil initially in place in the case where foam was pre-generated outside the core (55%, 61%, 59% and 46% are the oil recovery factors after waterflooding, respectively). The study revealed that drive foam strength has a bigger impact than its surfactant slug salinity.

Foam is useful as an enhanced oil recovery method to reduce gas mobility and prevent gravity override to improve sweep efficiency. Foam is generated in porous media when exceeding a critical velocity and pressure gradient, that usually occur near to an injection well. There is the uncertainty of foam generation in the low-pressure gradient and velocity further from the injection well. However, foam can be generated at such a permeability change with no minimum pressure gradient or superficial velocity. In field application, permeability contrasts originate from cross-bedding in fluvial sand-channel reservoirs, reservoir layering, and sharp heterogeneity changes over a few centimeters to kilometers of the formation.

This study describes series of experiments with various of gas fractional flows, and injection velocities. The experiments use synthetic sintered glass porous media to create consolidated nature of porous medium with a sharp boundary between low- and high-permeability layers. The experiments are augmented by the medical X-ray computerized tomography (CT) machine, which can be used to generate dynamic images of the core flood.

This study proves that capillary snap-off plays a dominant role in foam generation across a sharp heterogeneity boundary (low to high permeability) regardless of the superficial injection velocity that is applied in the system. In our experiments, as the injection velocity reduced, the magnitude of pressure fluctuations increase. Across the permeability jump, as the injection velocity reduces, the observed pressure gradient during foam generation is also higher. However, foam is difficult to propagate at very low injection velocity, in our case 0.17 ft/day (0.025 ml/min). These conditions observed at sintered glass core with permeability contrast 3.8:1 (0.17 ft/day and 80% of foam quality) and permeability contrast 14:1 (0.17 ft/day and 95% of foam quality). In terms of gas fractional flow, the CT results verify the pressure gradient profile at different gas fractional flow experiments (60%, 80\%, and 95%), foam is indeed generated at the permeability contrast and propagates downstream to the outlet of the core.

Foam is a promising solution for improving the poor sweep efficiency of gas injection for enhanced oil recovery (EOR), in that foam lowers gas mobility significantly by trapping gas bubbles. Most of oils destabilize foam, the effect of which dominates foam strength when foam is in contact with oil and is key to success of foam EOR, but not yet fully understood. This study focuses on understanding oil displacement by foam in lab scale and providing insights for field-scale applications. We carry out the study from two perspectives: a) X-ray CT corefloods that give data on both saturation and pressure response in a foam displacement and b) data fitting to corefloods results.

Experimental studies are conducted with two types of simplified model oil to avoid confusion of the effect of multi-components of crude oil: hexadecane (C16) that is benign to foam and a mixture of C16 and oleic acid that is greatly detrimental to foam stability. CT scanning provides data on oil saturation (So) and distribution along a core during the corefloods. Such key information relates So to foam dynamics as implied by pressure response, in particular foam generation and propagation suggesting efficiency of oil displacement by foam. Specifically, foam is injected in two ways: co-injection of surfactant solution and gas with the intention to generate foam in situ in the presence of oil and injection of pregenerated foam. The co-injection serves to check the effect of oil on foam generation and propagation (anti-foaming effect) in the displacement. The second way investigates de-foaming effect of oil on foam displacement. The results show that foam generation in situ in the presence of oil is possible only when the oil is relatively benign to foam. When oil is very detrimental to foam, the in-situ generation is very difficult even at oil saturation as low as residual oil saturation. The displacement of pregenerated foam with oil consists of two stages of foam propagation due to change in So. Foam drains down So with a weaker strength due to high So in the primary propagation. In the secondary propagation, foam propagates faster with a larger strength, pushing oil forward like a piston.

Fitting coreflood data is then performed using a most widely used local-equilibrium implicit-texture foam model in CMG STARS™ simulator. We propose a fitting guideline for estimating foam simulation parameters based on steady-state foam flow data with oil in a recent study that does not give data on So. The model parameters estimated using this method serve as an initial guess for finding the optimal parameters to fit the coreflood data in simulation. A simulator for foam simulation in STARS is set up for this purpose. A scheme is then developed to optimize the model parameters in fitting the dynamic data. The challenges and difficulties in the fitting are briefly summarized for future work.

EOR processes employing gas injection can be very efficient in recovering oil where the gas sweeps. Unfortunately, gas injection has poor sweep efficiency because or reservoir heterogeneity, viscous instability and gravity segregation of injected gas to the top of the formation. Foam can improve the sweep efficiency in gas injection in Enhanced Oil Recovery. The best injection strategy to overcome gravity override in homogeneous reservoirs is a SAG process with a large slug of surfactant followed by a large slug of gas. An additional advantage of SAG injection is increased gas injectivity. Water is displaced from the near-well region where foam weakens, this raises gas mobility and increases injectivity. However, during liquid injection, the injectivity is considered to be poor.
Liquid injectivity is not fully understood during SAG process. In this study several core-flood experiments were conducted to investigate how injectivity is affected by the injection strategy. Through these experiments, it has been found that the gas injection flow rate has no significant effect during the gas injection period, foam collapses after roughly the same number of pore volumes of gas injected regardless of the injection rate.

During the liquid injection period, liquid was injected at different flow rates following a gas injection period. The results suggested a moderately shear-thinning behaviour. Liquid injection rate was increased 10, 40 and 100 times, but the rise in pressure gradient is not proportional to the increment in injection rate.

Furthermore, the effect of the size slug injected was investigated on the subsequent liquid injection. Results show that during prolonged periods of gas injection after foam, a region near the inlet is formed in which the gas mobility is much greater and the liquid mobility is much greater than downstream during the subsequent liquid injection. The bigger the gas slug size, the better the subsequent liquid injectivity in the nearest region to the inlet.

The effect of foam quality was studied; it has been found that foam quality has no big effect during the subsequent gas and liquid injections. The results of foam injection at 0.60 and 0.95 quality followed by gas injection show that foam collapsed after roughly similar number of pore volumes injected regardless of foam quality. During the liquid injection period the trends of the pressure gradient were similar at foam initial quality injection 0.60 and 0.95.

Finally, in order to verify the capability of the radial model developed by Gong et al. \cite{Gong}, the experimental data was fitted to the linear-flow and radial-flow models. The results suggest that the simulation based on Peaceman equation underestimated the gas and liquid injectivity in SAG process, and furthermore, the conventional simulator cannot represent the effect of gas injection on the subsequent liquid injection.

Traditional reservoir modelling utilizes a stochastic approach centered around statistics to generate a 3D representation of the reservoir. While the results of a stochastic approach are favorable, they tend to lack the detail that is necessary to fully understand the different aspects of the reservoir, more precisely, the inclusion of heterogeneities. A possible solution to this problem is the use of process-based models. Process-based models utilize the physical processes involved in the transportation, deposition, and erosion of sediments. As a result, the models generated are more complex in nature and better represent what is found within the subsurface. The use of process-based models within reservoir modelling is a a relatively new process that has yet to be fully utilized due to the difficulty in calibrating the models with well data. Before process-based models can be tested on their viability to include the multi-scalar heterogeneities, the model must be calibrated to match the real-world data. To test this, a combination of field work, lab work, and computer simulations is required. In this experiment, the Roda Sandstone Member, a Gilbert-type delta deposit in Northern Spain, was chosen as the unit of focus. The Roda Sandstone consists of multiple prograding sand lobes, with Roda Y being chosen as the focus of this experiment. The Roda Y sandstone exhibits a predominately medium and coarse grain distribution in the central locations of the sand lobe, and a fine and very fine distribution in the distal locations. Five simulations were run within the process-based modelling software "Delft3D", each with varying sediment input parameters, to observe the effects on the results. The results for the simulations show a strong calibration for each of the five simulations for coarse and medium grained sand, with a percent difference between the model results and the field data of 4-8%. The fine and very fine data contain a higher average difference between the two data sets, ranging from 18-23%. The difference for mud averages around 11%, with predominately more mud being deposited within the simulations. The large differences for the fine and very fine grained can be attributed to the difference in the size and shape of the sand lobe produced by the simulations. In locations were the two data points are equivalent in regards to depositional location within the sand lobe, a high correlation is observed. The results indicate that process-based models have the potential to be a very useful took within reservoir modelling. As this is the first step in a series of steps, additional testing is required for the additional aspects involved in utilizing process-based models to better incorporate heterogeneities within reservoir models.

Scope: Surfactant-alternating-gas (SAG) is the preferred method of foam injection to improve sweep efficiency in enhanced-oil-recovery (EOR). Here, for the first time, fractional-flow theory is extended to include the shock for gas injection in the high-quality regime for radial flow in a non-Newtonian SAG process for shear-thinning and shear-thickening foams.
Methodology: To represent non-Newtonian behavior in the high-quality regime, the limiting water saturation for foam stability varies as superficial velocity decreases with radial distance from the well. We look at the interactions between the shock and the characteristics. The mobility control at the shock front and injectivity are examined. The system is compared to a Newtonian foam.
Results and conclusions: For shear-thinning foam, the foam front’s dimensionless velocity decreases with time, while the characteristics accelerate and collide with the shock. As the foam front propagates, the mobility ratio and mobility control becomes more favorable. The injectivity decreases until breakthrough, then improves slightly.
For shear-thickening foam, dimensionless velocity of the foam front increases with time, while the shocks slow down. Mobility control worsens and injectivity improves as the foam propagates, even before breakthrough. For extremely shear-thickening foam, the near-wellbore region exhibited shear-thinning behavior. This has three causes: a shift from the high- to the low- quality regime, the extrapolation of f mdry over a too large range, and the Namdar Zanganeh correction.
Recommendations: Future models should replace the shock with the colliding characteristic, instead of eliminating the characteristic. For shear-thickening foams, new characteristics should split off from the shock. Include the shear-thinning factor for the low-quality regime to check if the foam is still in the high-quality regime.

Non-Newtonian foam flow in a reservoir can be modeled numerically by discretization of the corresponding analytical formulas. The injection of foam is compared to the injection of water by comparing the injection pressures, which is represented as a dimensionless pressure rise at the injection well. The model first applies the forward-difference method to compute the changes in water saturation over space and time as the foam is injected. These changes in water saturation are related, via Darcy’s Law, to changes in dimensionless pressure. The non-Newtonian foam behavior is implemented in the model by making the gas relative permeability a function of position in radial flow, based on the exponent defined for a power law fluid.
The validity of the model is assessed by a comparison with an analytical model using the method of characteristics to simulate Newtonian foam flow. This model was created by A.H. Al Ayesh. From this comparison, it follows that the numerical model converges to a correct solution for sufficient fine discretizations. Finer discretizations do however introduce drawbacks, such as long computation times and high computer-memory requirements. Another drawback of the numerical model is the inevitable error that is introduced by a numerical artifact in the computation of the total relative mobility in each grid block at the front as foam advances. This error can only be reduced by even-finer discretizations.
The validity of the model for non-Newtonian foam flow simulations is not assessed directly in this thesis. But the model is expected to have similar or coarser grid-refinement criteria for shear-thinning foam flow, and finer or similar grid refinement criteria for shear-thickening foam flow.

The mobilization of the trapped residual oil is an important part of Enhanced Oil Recovery. The desaturation of nonwetting fluids from porous media is often described using capillary numbers which are a ratio of viscous forces over the capillary forces between the wetting and the nonwetting fluids. Twodimensional microfluidic devices (micromodels) play an important role as they allow for the visualization of the two phase flow in porous media. Even though the existing definitions for capillary numbers work fine for describing the mobilization of the trapped nonwetting phase in geological rock, problems arise when applying these definitions for capillary numbers on micromodels. The conventional definition of the capillary numbers do not allow to visualize the desaturation of nonwetting phases in different micromodels on a single trend. This research presents the derivation of a new definition of a capillary number that can be used to better analyze the mobilization of trapped nonwetting ganglions inside micromodels. The new capillary number is based on a force balance on a trapped ganglion and the corresponding mobilization criteria of the trapped nonwetting phase. The new definition of the capillary number consists of the conventional definition of the capillary number and a geometric term that accounts for the geometry of the micromodel, including the sizes of the pore bodies and throats as well as the ganglion length. The functionality of similar definitions of the capillary number for roughened fractures has previously been published by Al Quaimi and Rossen (2017). The functionally of the new capillary number has been tested by analyzing published desaturation data for various micromodels, each using different wetting and nonwetting phase combinations using both the conventional and the new definition of the capillary number. It is found that the new definition allows for better analysis of the mobilization of the trapped nonwetting fluid inside micromodels, as the desaturation curves for different models can now be visualized by a single trend. Also, it is suggested that the geometrical parameters of the new equation are more significant for describing the mobilization of the trapped nonwetting phase than the of the medium and the interfacial properties of the wetting and nonwetting phases.