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Ultrasound has a number of applications within Enhanced Oil Recovery (EOR). Most of these are focused on down hole cleaning. An alternative use of ultrasound is creating emulsions with the purpose of mobility control. The goal of this study is to observe the effect of ultrasound on the emulsification of oil and water. For the experiments that were covered in this study an ultrasonic bath was used. Characterizing the energy distribution within the ultrasonic tank was the first crucial step. It was observed that salt dissolution was enhanced as a result of sonication. The dissolution was used as a measure for the local energy intensity. A significant amount of salt had gone into dissolution as a result of sonication. This is a novel method to characterize the energy distribution of an ultrasonic bath Two high energy regimes that were localized with the dissolution method were used for the emulsification of the oil and water. A rang of surfactant concentrations were tested. The goal was to study the effect of a varying surfactant (alpha-olefin-sulphonate) concentration on the result of the emulsification process of hexadecane and water. After filling a test tube with a surfactant solution and oil and positioning it in the previously localized high energy spot in the ultrasonic bath the sample was sonicated. After 30 minutes of sonication, either an emulsion or a gel-like substance was observed between the surfactant solution and the oil. It had been observed that the type and quantity of this “middle substance” depends on the surfactant concentration. The gels that were recovered from the test tubes were freeze-dried and analyzed with a scanning electron microscope. The gel has a dual porosity. The large-scale pores have a spherical shape and are 50-500 μm in diameter. The smaller pores are shaped as wormholes. They are 1-3 μm in diameter. The gel could prove useful for near-wellbore applications. The emulsions form easily under the acoustic stimulation, hence application to mobility control or other EOR related applications is thought feasible.

For the calculation of drilling loads knowledge of the Coulomb friction coefficients for friction between drilling tubulars and casing or drilling tubulars and open hole is essential. To reduce drilling costs for geothermal wells the casing while drilling, CwD technique is considered. CwD reduces drilling time by eliminating round trips, because the well is drilled and cased simultaneously, thus improving efficiency. Drilling loads are the result of friction in the borehole, the weight of the string, and the borehole and drillstring geometries. Drilling costs will be reduced even more if the drilling loads can be reduced. In the Coulomb friction model the ratio between the friction force and the normal force is constant. Thus, if the normal force is reduced, the friction reduces. This can be achieved by replacing the regular heavy steel casing by lighter composite tubulars. Dynamic drilling loads like torsional vibrations can be triggered by the difference in static and dynamic Coulomb friction coefficients. A large difference increases the chance on the occurrence of such friction-induced vibrations. The objective of this study was to compare the Coulomb friction coefficients for steel and composite tubulars, under both static and dynamic conditions, through experiments with the different samples in sand and steel 'boreholes'. If the friction factors for composite casing are known, the dynamic drilling loads for CwD with composite casing can be predicted more accurately. Unfortunately, with the set-up used to measure the dynamic friction coefficients no conclusive results have been obtained. The Coulomb friction coefficients for steel on steel and for steel on ‘rock’ were constant for all applied loads, but the coefficients for composite on steel and for composite on ‘rock’ behaved unexpectedly. In particular, decreasing the normal force seemed to increase the friction coefficients to unrealistically high values. Also the static friction coefficient measurements of the composite casing showed some inconsistencies, which can be contributed to the irregular surface caused by the production process.

This work is based on the idea that an acid mixture of hydrochloride and sulpheric acid react with the calcite in a chalk oilfield to create anhydrite which has a larger molecular size. This will clog the present fractures to prohibit that these fractures sometimes shortcut the injected water from the injector well to the producing oil well which otherwise would result in artificial thieve zones. In this work mass balance calculations and experimental lab work has been done to see how the acidic reaction works. It is concluded that during the conversion of calcite to anhydrite 60% of the resulting CO2 is dissolved in the present liquid; the rest is in the gaseous phase. The samples of fractured chalk are approximately 30 cm long and have a diameter of 10 cm. The fracture is situated in the flow direction. The samples are tested under reservoir conditions, and the flow rate of the acids is 2 ml/min. The resulting permeability change indicates that the fracture is sealed after half an hour of acid injection, but this seal in the fracture is only a pasty substance clogging the flow. After approximately six hours of injection the first wormholes appear and the fracture is totally sealed. Mass change is calculated based on the amount of anhydrite created during acid injection. The mass changes are equivalent to the mass change measured during the experiment. CT-scans are made before, during and after many experiments and each scan series of approximately 300 images. These images are used in a specially written program to divide all present volume components in the chalk: fracture, calcite, anhydrite, wormholes and fossils. They are also used to calculate volume percentages, and coincide with the calculated weight percentages. Fracture experiments under reservoir temperature and pressure conditions and Brazilian tests under atmospheric are done on the sealed samples to see if the fractures can be reopened. The samples were tested with an annular pressure of 310 bar, 80oC and injection pressure of 270 bar. The production pressure was released, even with a pressure difference over the core of 160 bar and did not fracture. The tensile strength of the sealed samples proved to be as strong as original chalk samples without fractures.

The effect solutes have on the properties of solvents. The properties of pure solutions (with no solvent in it), a non-electrolyte solution and an electrolyte-solution are compared and discussed. Also a detailed information why these properties change.

Geothermal energy is hot and sustainable. A recent run for licences has sparked questions on the optimisation and recovery of geothermal energy from the subsurface of the Netherlands through optimal project placement. The effect of heterogeneities on interference of geothermal projects in the West Netherlands Basin and the target Early Cretaceous Delft Sandstone Member has not been sufficiently studied. The objectives of this study are: (1) to gain a better understanding of the geological setting, the depositional setting and the heterogeneities of the primary target Delft Sandstone Member; (2) to show the effect of heterogeneities in the subsurface on interaction and interference of flow on closely placed geothermal systems; and (3) to build a subsurface dynamic reservoir model with which optimal well performance and placement can be assessed. The basin evolution, depositional setting and depositional processes of the Delft Sandstone Member are determined by combining the available data. The seismic, well, core and cutting data are combined to build a static 3D reservoir architectural model of the Delft subsurface. The static model is incorporated with the flow characteristics from petrophysical log data and used for temperature and fluid flow behaviour simulations. By modelling flow and temperature behaviour, the flow rates and production temperatures of a single geothermal system and the interference of the different geothermal systems were determined and quantified. This study gives new insights and a better understanding of the reservoir architecture of the Delft Sandstone Member. The Vrijenban Syncline is the predominant structure in the Delft subsurface and the sediments of the Delft Sandstone Member are deposited by a meandering fluvial system in three different depositional settings, controlled by tectonic movement. The depositional characteristics related to subsidence and accommodation space increase can have a large impact on the reservoir behaviour of the Delft Sandstone Member. It has therefore been chosen to include this effect in the model. From the flow simulations in the Delft Sandstone Member it shows that different geothermal systems closely placed within one reservoir will have pressure interference. From this study it is concluded that multiple geothermal systems can be placed in one reservoir and sustain economic production temperature for over 30 years. Different geothermal systems in one reservoir will however communicate in the reservoir creating both positive and negative effects on flow that are large enough to respectively improve or badly affect the economics of a project. The results of this study will be a base case for further research as it will form a benchmark for future local and regional geothermal studies. Simulations of multiple well configurations to determine optimal well placement can now be performed. This will ensure and provide the foundation for a true roll out of geothermal systems through the western parts of the Netherlands.

Een onderzoek voor het Delft Aardwarmte Project (DAP) naar het verschil tussen composiet en staal in de geothermie. Er wordt met name gekeken naar scaling van composiet.

Worldwide rising gas demand is creating new opportunities for low-permeability gas reservoirs to be exploited with large hydraulic fracturing campaigns. These so-called tight gas reservoirs have been subject of much research over the past three decades, primarily because it is difficult to optimize recovery. In this thesis, post-fracture production of tight gas reservoirs is simulated and interpreted through well test analyses. The focus lies on the impact of unconventional reservoir behaviour, specifically the impact of leakoff water on gas production and assessing the accuracy of post-fracture evaluation using production data and well tests. Specific characteristics of tight gas reservoirs, such as high capillary pressure, a ‘permeability jail’, and reservoir heterogeneity, may invoke phase trapping mechanisms that could potentially harm gas production. The ‘permeability jail’ is a hypothesis that gas-water relative permeability functions include a large saturation range with little or no fluid mobility, caused by the complex pore-structure of tight gas sandstone reservoirs. This thesis presents reservoir simulations of both the short and the long-term gas and water production, performed with a commercial numerical simulator. Simulations show that high capillary pressures alone do not harm gas production significantly. Assuming a permeability jail in lower-permeability reservoir zones in a heterogeneous reservoir results in an extended cleanup period and a reduction in total recoverable gas. This result is comparable to the simulation of mechanical or chemical damage to the reservoir surrounding the fracture, or so-called fracture face damage. With mechanical or chemical damage, the water production is impaired initially and slowly recovers with time. This distinguishes this type of damage from a permeability jail, which shows rapid water flow-back of approximately 50% of the leakoff water. Finally, the impact of leakoff water on a permeability jail is severe. Therefore, it is advisable to control leakoff during the treatment. The simulation output data is analyzed with a commercial pressure transient analysis software package. The well test analyses show that a heterogeneous reservoir with permeability jail damage can also be interpreted as a homogeneous reservoir with either a very short or low-conductivity fracture: all three hypotheses fit the well-test data. This confirms that well tests may be inconclusive for distinguishing among these cases. Subsequent performed simulations show that reduction in fracture length does not extend the initial cleanup period, but strongly correlates with a shift of the production decline curve to lower gas rates. A reduced fracture length and damage from leakoff and a permeability jail are therefore distinguishable. On the other hand, it’s difficult to separate production results for a model with a low-conductivity fracture from a model with permeability jail damage: both show strongly reduced initial gas rates and followed by long cleanup periods. Water production can be used to discriminate between a fracture with reduced permeability and reservoir damage, however. This allows for a correct diagnosis and appropriate actions to be taken to optimize subsequent fracture treatments.

The Ram Group in Jordan forms part of a massive and voluminous quartz-rich blanket that covered North Africa and Arabia, the former northern margin of Gondwana during the Early Paleozoic. The lack of vegetation on the vast peneplained and tectonically stable margin resulted in the development of extensive alluvial systems markedly different in scale from modern systems. In the Petra area, the Ram Group is conformed by the Salib, Abu Kusheiba and Umm Ishrin formations. Its onset and development are admirably displayed allowing a unique oportunity to perform detailed sedimentological studies. In the paleogeographic context of the Early Paleozoic, the detailed analysis of five lithofacies and interpretation of their three major associations in terms of architectural elements, the study of the mineralogical development throughout the sequence and the ichnofacies content from new ichnofossil discoveries are all gathered in order to reconstruct a depositional and architectural model for the Ram Group. The base of the sequence buries a remarkable 100-metre high paleorelief of the Precambrian basement inherited from volcanic activity. Upward, the sedimentary package describes a 110-metre-thick fining/thinning (salib Formation) and coarsening/thickening (Abu Kusheiba Formation) cycle until drastic development of a >500-metre-thick, massive, medium-grained cross-bedded quartzarenite (Umm Ishrin Formation). The environments of depositions evolved from shallow marine shelf to delta-front and delta braidplain until definite onset of a continent-wide alluvial plain dominated by shallow, perennial, sand-bed braided rivers on the distal margins of Gondwana. Short-lived transgressions and tidal currents reworked parts of abandoned braidplains. The Umm Ishrin Formation is an excellent analogue for subsurface braided hydrocarbon reservoirs. Reservoir characterization from outcrop studies results in a vertical stack of laterally extensive sheet-like units with remarkable high net-to-gross ratios. Radial flow is expected and drainage would be driven under gravity dominated flow due to good hydraulic connectivity in a rather thick and homogeneous sand-rich formation. Reservoir heterogeneities such as small, isolated fine-grained interbeds are randomly distributed through the reservoir. Rather than impeding cross-vertical flow, these barriers may be useful in preventing water or gas coning when correct placing of production wells.

Large amounts of natural gas hydrates have been found in sub-oceanic deposits and beneath permafrost regions. It has the potential to become a major hydrocarbon resource in the near future. Research is needed to evaluate the production possibilities of this new resource. CH4 hydrate dissociation and production is an endothermic process and a production challenge is the reservoir temperature reduction. CO2 is thermodynamically favoured over CH4 in the hydrate form and it has been suggested to use CO2 to prevent cooling by replacement of CH4 hydrates with CO2 hydrates. This technique has three advantages: sequestration of CO2, increased CH4 production and maintaining formation stability. The effect of CO2 injection on the CH4 production from a hydrate reservoir has been investigated by numerical simulations. A sensitivity analysis on the CH4 production has been performed by varying the injection pressure, temperature, reservoir properties, hydrate blockage models, intrinsic kinetic rates for CO2 hydrate formation and numerical parameters. The research has been performed by running numerical simulations using the kinetic simulator STARS from CMG. A 3D homogeneous class 2 hydrate reservoir was constructed with a production well completed in the hydrate zone and an injection well completed in the free water zone, injecting liquid CO2 in the free water zone below the CH4 hydrate zone. The injection and production well pressure were regulated to create CO2 hydrate forming and CH4 hydrate dissociation conditions in the reservoir. The simulation results have shown that when CO2 is injected, the cumulative CH4 production can increase with 50-60 %, while storing significant amounts of CO2 simultaneously. 2 % of the injected CO2 was produced at the production well. CO2 hydrates were formed directly under the CH4 hydrates, supplying the dissociating CH4 hydrates with a low grade heat source. No upward moving front of CO2 was observed. It is concluded that CO2 injection only increases CH4 production when the temperature of the reservoir is too low to support further hydrate dissociation. The highest recovery rates are achieved with low injection pressures. Injection of CO2 in the gas phase is favoured and the intrinsic kinetic formation rate for CO2 hydrates is a major influence on the CH4 production. It is concluded that CO2 injection in a Class 2 hydrate reservoir could increase the CH4 production under certain conditions.

This project develops a software tool to model pressure loss of two phase flow in the annulus of a well during underbalanced drilling. By adjusting the Mukherjee and Brill correlation for production/injection wells, insight into which parameters are of influence in predicting the frictional pressure drop during underbalanced drilling is gained. Also the difference between the use of oil-base mud or water-base mud is presented. Underbalanced drilling is the oldest drilling method which over the past years received new attention for bringing new life to an old reservoir. With no reservoir impairment, this method can achieve a higher recovery factor if completed 100% underbalanced. For the success of an underbalanced drilling operation, understanding the annular frictional performance of non-Newtonian mud is crucial. This is a key factor in the development of the hydraulic program which is used in the selection of the drilling equipment. Although several simulators exist, none of them accurately predicts the pressures which are experienced in reality. In this project a power-law model for predicting frictional pressure loss in eccentric annulus is used instead of the formulas defined by Mukherjee and Brill. After selecting the parameters that have a potential impact on the frictional pressure loss, a range for each parameter was defined and a sensitivity analysis was performed to quantify the impact due to changes in each parameter.

In-situ combustion (ISC) is an enhanced oil recovery process during which air or oxygen-enriched air is injected into a reservoir. The oil in the reservoir reacts with the oxygen and the so-called combustion front is formed and propagates through the reservoir, generating heat and flue gases. During the process, numerous chemical reactions take place in different zones and temperature ranges. For the description of the process the oil is represented by pseudo components. The definition of the pseudo component defines the reaction schemes implemented in the numerical simulator. The reaction kinetics are described by relative simple order reactions for which the reaction rates are calculated using the Arrhenius-type equations. Estimating the input parameters of the Arrhenius equation is a giant obstacle in ISC modelling. Combustion tube experiments are performed to acquire oil, water and gas production data, the effluent composition and temperature profiles which depend on the oil and reservoir rock properties. Estimating the Arrhenius parameters can be done by history matching these experiments. Due to the quite large amount of parameters non-unique solutions are found. Unfortunately, so far the resulting adjusted parameters are not tested if they describe a chemical-physical sound and realistic behavior. In this research an ISC tube experiment with an Athabasca bitumen was simulated using a commercial thermal simulator (CMG STARS). The cumulative oil and gas production and the temperature profiles of the experiment were used for verification of the simulations. The first simulation was done with the input parameters as stated by Yang and Gates (2009). In this simulation the reaction rate parameters were chosen such that coke formation from asphaltene by cracking already commences at temperatures of around 343 K and coke formation from asphaltenes by oxidation at temperatures of around 650 K. Further, in the applied reaction schemes methane combustion is assumed to be up to a factor 1030 slower than hydrocarbon gas combustion. In this study, the reaction kinetics were changed to see the influence of the reaction kinetics parameters of asphaltene cracking and asphaltene oxidation at lower temperatures. Further, the reaction rates describing methane combustion was set equal to the kinetic parameters of hydrocarbon gas combustion. From these simulations it was found that the hydrocarbon gas combustion reaction does not significantly influence the ISC process. Changing the reaction kinetics of asphaltene cracking and oxidation does influence the ISC process significantly; asphaltene cracking occurs fasters and starts at lower temperature, more coke is formed and combusted in the simulation but less oil is produced than in the base case. Furthermore, the injection rate of the air was varied to identify the impact of the fuel/oxygen ratio on the production data. A higher air injection rate shows that the combustion front moves through the reservoir in a shorter amount of time; which indicates that it is possibly economically favorable to inject air at a higher rate into an oil reservoir in which ISC is conducted.

An experimental study on the leak-off of oil based drilling fluid sandstone cores is reported. First we revised the theoretical models for the rheology of the drilling fluid, the flow behavior of drilling fluids in the drill pipe and annulus, and filtration mechanisms. Then systematic static leak-off experiments were carried out using an innovative method where CT scans taken at time intervals were used to visualize and accurately quantify infiltration of fluids in a sandstone core. Different compositions of oil based drilling fluids were investigated, to examine the influence of various particles on the external filter cake and internal filtration. Scanning electron microscopy was used to characterize the external filter cake and internal filtration. The results give accurate measurements of the filtration volume of the drilling fluids. Depending on the composition of the drilling fluid, the formation of external filter cake could be visualized on CT images. The core flow experiments are matched to the theory for linear static filtration. The results lead to new insights concerning the build of external filter cake and internal filtration. The experiments use real sandstone cores giving more realistic data than using an API press test and filter paper. This work creates a basis for future improvement of oil based drilling fluid, by providing a better understanding of mechanisms involved in leak-off control.

Recent improvements in dynamic reservoir modeling have led to an increase in the application of model-based optimization of hydrocarbon bearing reservoirs. Numerous studies and articles have indicated the possibility of improving reservoir management using these dynamic models, coupled with methods to reduce uncertainties in the static models, to optimize reservoir performance. These studies have focused on maximizing the life-cycle performance of the project. Thus life cycle optimization is essentially a single-objective optimization problem. In reality, short-term targets usually drive operational decisions. The impact of short-term targets should be included in the optimization to achieve a more realistic solution. The process of optimizing these short-term targets constrained to life cycle targets is a form of multi-objective optimization. Several methods have been suggested to achieve multi-objective reservoir flooding optimization (Van Essen et al. 2011). These methods have been implemented with the adjoint formulation. This thesis proposes the use of an ensemble-based optimization technique (EnOpt) for multi-objective optimization. The optimization of smart wells or production schedules (inflow control valve (ICV) settings) is the objective of this work. We also propose variations to the existing multi-objective algorithms suggested by Van Essen et al. (2011). We propose the use of the BFGS algorithm to improve the computational efficiency. Undiscounted Net Present Value (NPV) and highly discounted NPV are the long-term and short-term objective functions used in this thesis. We also propose an extension of the optimization functionality to better cope with model uncertainties. This robust ensemble-based multi-objective production optimization framework has been applied and tested on a synthetic reservoir model. In our test cases, the ensemble-based multi-objective optimization methods achieved a 14.2% increase in the secondary objective at the cost of only a minor decrease between 0.2-0.5% in the primary objective.

A global and industry wide dataset was data mined for determinants of recovery efficiency. Understanding of the factors that are driving variance in reservoir performance is essential for benchmarking current performance and for the screening of new opportunities. The following insights in the origin of variance in reservoir performance could be extracted from this analysis. Global trends for recovery factor with drive mechanism, reservoir type, geological age, lithology and depositional environment were extracted through subgroup analysis. Other property trends, such as porosity with depth and geological age, were found to be basin specific. The internal structure of the database and correlations was revealed through principal component analysis. Relative importance of the predictor variables was determined using automatic multivariate linear regression. It was found that the predominant variables include: API gravity, permeability and reservoir temperature. Additional data was identified through combination of literature review, dimensional- and statistical analysis. The following variables are suggested: dip angle, flow rate, fractional water cut, and pressure drop. Furthermore continuous scales for heterogeneity and fracture intensity, especially for carbonate reservoirs are suggested. To express the confidence level for each reservoir in the database, categorical variables for maturity and data quality are proposed. This research forms the basis for future data mining of the dataset and further improvement of the TQ EUR TOOL in which the data is stored. In a wider context this report presents a high level overview of observations on reservoir performance based on actual reservoirs worldwide rather than laboratory data or theory.

Alkaline Surfactant Polymer (ASP) flooding is a chemical EOR technique that takes advantage of both interfacial tension reduction and mobility control. Core flooding tests show almost 100% recovery when the experiment is carried out under optimal conditions, i.e., a middle phase micro-emulsion characterized by extremely low interfacial tension is formed when a phase behavior test is done. In the field, reservoir heterogeneity causes mixing, which takes the system away from its optimal condition. Another major drawback of the ASP floods is the high cost of the associated chemicals. In some cases the logistics can also be a major challenge. Therefore this thesis considers the application of ASP at non optimal conditions. We study this application by performing series of core flood experiments. For a given surfactant concentration we determined the optimal condition by varying the alkali concentration, which turns out to be 1.75 w/w% of Sodium Carbonate (Na2CO3). Subsequently we performed vertical flow experiments using alkaline weight percentages from 1.0 % to 2.25 % with increments of 0.25% around the optimum. Initially we used a 38.3 cm core, which gave an unexpected low recovery of 68% to residual oil, after injection of two pore volume (PV). Injection of over-optimum solutions resulted in even worse recoveries, while injection of under-optimum solutions led to higher recoveries at chemical break-through for 1.5 w/w% and 1.25 w/w% before it dropped again for 1.0 w/w%. To understand this behavior we repeated the experiment with shorter cores (30 cm and 17 cm) at optimum conditions, which gave a recovery of more than 90% (95% of the oil initially in place (OIIP)), which value is often encountered in literature. We propose that instabilities may be the cause of the low recoveries after a stability analysis shows that the system apparent viscosity is higher than the viscosity of the displacing ASP solution.

The static leak-off of oil-based drilling mud into liquid-saturated cores was studied experimentally. A simple model for the leak-off was first developed extending an earlier model for the static filtration into unsaturated core. CT scan aided static filtration experiments were performed in brine and oil and brine saturated cores, simulating reservoir saturation regimes. Formation of external filter cake and internal filtration of solid particles were visualized and leak-off volumes were determined as function of time. At the end of the experiments the formed external filter cake and internal particle deposition were characterised with the aid of an Electron Scanning Microscope. Using drilling fluids containing carbonate particles it was found that leak-off volumes for saturated cores are larger than for unsaturated cores. It was observed further that leak-off volumes increase with the particle size, i.e. consistently with a more permeable external filter cake and limited internal filtration. Leak-off volumes decreased when using smaller hematite particles or using larger range of (barite) particles sizes. The filtration volumes for the smaller sized drilling fluid components in brine saturated core experiments were found to be larger than filtration volumes found for dry core experiments in previous work.

The upstream oil and gas industry focuses increasingly on unconventional gas resources to maintain the level of its hydrocarbon reserves. To unlock the full potential of gas shale reservoirs, horizontal wells are drilled and active stimulation of the reservoirs, in the form of multi-stage hydraulic fracturing, is performed. This new technique has radically changed the energy future of the United States and is on the forefront of changing it in Europe as well. The hydraulic fracturing treatment is a costly, resource intensive and potentially environmentally dangerous procedure. The objective of this thesis is to create a realistic and versatile gas shale reservoir model and optimize the placement and number of hydraulic fracture stages along a horizontal well bore, thereby maximizing the production of gas while minimizing the amount of money that is spent to do so. On the basis of the computationally efficient ensemble based optimization of vertical well placement, an idea coined and investigated by Leeuwenburgh et al. (2010), it is postulated that numerical optimization can aid in finding the optimal placement of hydraulic fracture stages along a horizontal well bore in an equally computationally efficient manner. Three gradient-based optimization algorithms (Ensemble based Optimization: EnOpt (Chen, 2008), Simultaneous Perturbation Stochastic Approximation: SPSA (Spall, 1998) and finite difference gradient estimation) that work with continuous variables, are used to approximate the gradient. Because hydraulic fracture stage locations in a reservoir simulator are commonly treated as discrete variables (well grid block indices), standard implementations of gradient-based optimization are not applicable for optimal hydraulic fracture stage placement. We propose three distinct variable parameterizing placement methods to overcome the inherent continuous to discrete variables conversion issues. After the theoretical arguments about the strengths and weaknesses of the proposed optimization routines, both single well and multiple well scenario experiments are performed. Good results are obtained from the various experiments which favor an optimization with the EnOpt algorithm in combination with the fracture stage interval placement method.

In this BSc-thesis a Surfactant-Alternating-Gas (SAG) foam displacement is represented by an idealized model. Shan and Rossen show in the article ‘Optimal Injection Strategies for Foam IOR’ (2004) that this model, though greatly simplified, is a useful representation of a foam displacement in the physical world, where pressure gradient is the most important factor in controlling gravity override. The process of building the model and numerical problems and solutions are discussed. The foam displacement is extended beyond the range computed by Shan and Rossen, to an dimensionless position XD of 4. The following cases are considered: kv = kh, 0<kv<kh and kv = 0. A comparison shows that the smaller the kv, the less convex the foam displacement front is. Ironically, in this case, increasing vertical permeability reduces the extent of gravity segregation of gas and increases vertical sweep.

Oil recovery in fractured reservoirs by water flooding critically depends on the wetting properties of the matrix blocks between the fractures. The recovery from oil-wet reservoirs is almost negligible. In incompletely oil-wet systems, the presence of initial water may change the wettability characteristics so that very slow imbibition and some oil recovery can occur. The hypothesis in this thesis is that water soluble solvents enhance the wettability change and lead to enhanced recovery. Another mechanisms is that the water soluble solvent dissolves in the oil and oil is recovered due to swelling. The solvent may also decrease the oil viscosity and the interfacial tension between the oleic and aqueous phases. This thesis comprises of an experimental study into the recovery enhancement by water soluble solvents (diethyl ether). We used an Amott imbibition cell studying oil saturated samples of various wettabilities, permeabilities using oil of different viscosities and two different solvent concentration in the aqueous phase. In the first stage of the experiment the water-wet core was exposed to brine without solvent. In a second stage the core was put in a new Amott cell, which was filled with solvent/ brine mixture. The additional recovery was small. We found that the oil recovery is faster when the oil viscosity is lower, but the ultimate recovery is about the same. The recovery with higher permeable samples is faster, but ultimate recoveries are close. Low permeable samples benefit from the presence of solvent, but the effect is rather small. For the oil-wet samples we also started with exposing the core into pure brine without solvent. In spite of being oil-wet, oil was recovered from these samples. In view of the large inverse Bond number it would appear unlikely that this a gravity drainage effect; however the produced oil droplets are coming from the top. Contrary to the water samples there was a significant increase in recovery rate when the sample is transferred to another Amott cell where it is exposed to a mixture of solvent and brine. Now oil drops come from all sides. Therefore it is concluded that wetting alteration is the main mechanism of water soluble solvent enhancement in partially oil-wet cores. The effect of solvent on completely water-wet cores is less but significant.