This research was done in the framework of the RVO project on Development of a well impairment model for predicting geothermal clogging (DIMOPREC) .
The importance of developing new energy sources with lower carbon emissions than conventional hydrocarbon based energy sources has been globally recognized (Andrews-Speed, 2016). Geothermal energy is a lower carbon energy source, which can be used for both electricity production and for direct heat use (Fridleifsson, 2001).
However, radioactive mineral scaling can accumulate in filters and tubing of the geothermal facilities, which can be an operational hurdle as this scale needs to be removed with necessary caution. The problem is not only the riskiness of being exposed to radioactive elements, but also the rise in pressure caused by scale accumulation. This occurs at the filters resulting in more process stops. Another problem with the scaling is that it causes increasing injection pressure. Since there is a regulatory limit to this pressure, an increase in injectivity is not preferable. Here, a case of a low-enthalpy geothermal project is discussed where very limited radioactive galena, PbS, is found.
This geothermal system is modelled in the geochemical software package PHREEQC. The PHREEQC model shows that a fraction (78 wt.%) of the collected galena is produced in solid phase from the reservoir, and a smaller fraction (22 wt.%) is formed after the heat exchanger. Gamma ray logs analyses and sedimentation history are presented to find potential sources of Pb and S ions. With the geological history and literature study it is found that the radioactive Pb could be originated from the Zechstein and Rotliegend where it attaches strong to the Copper shale formations. Scale and water analysis show that most of the captured galena is transported in a solid phase into the geothermal facility.
In the second part we discuss the development of a SKID for scaling determination during geothermal production. It is proposed to design a new SKID with additional measurement and monitoring options, which is able to provide the requested input parameters for the PFREEQC model. Requested data acquisition for long term monitoring includes fluid pressure, flowrate, temperature and pH values. The mobile function makes it possible to sample at several surface locations along the line of the geothermal facility. The obtained and stored data can be analyzed and compared to other locations in order to find out whether or not the brine and its composition change, and if so, how it changes
In order to reduce the amount of radioactive PbS in the filters of the geothermal system, it could be considered to acidify the brine to a level where the minerals are dissolved. In addition, increasing the facility pressure and/or increasing the minimum brine temperature after the heat exchanger, could reduce the amount of galena precipitation captured in the filters of the geothermal facility.

Naturally fractured reservoirs (NFRs) gain much attention worldwide because they are often encountered in aquifer remediation, CO2 sequestration, and hydrocarbon extraction. In hydrocarbon extraction, however, oil recovery by gas injection in NFRs is usually low, because of poor sweep efficiency. During gas injection, the displacement front is unstable. Conformance problems, such as gravity override, viscous fingering, and channeling, take place because the gas has a lighter density and lower viscosity compared to reservoir fluids, and tends to flow preferably through high-permeability zones in heterogeneous reservoirs. In addition, open fractures can have much greater conductivity than the matrix. As a result, gas flows through fractures, leaving much of the matrix unswept. Foam, by adding surfactant solution to gas injection, can effectively mitigate conformance problems by greatly reducing the mobility of gas. During foam flooding in porous media, the displacement front is more stable, and more gas is diverted to unswept zones, hence improving the sweep and increasing oil recovery. Foam can also be created in fractures, where it builds up a viscous pressure gradient and thus diverts the flow of gas into the matrix. As a result, the sweep is improved. In the field, foam pilots have achieved an increase in oil production rate and a reduction in gas/oil ratio. Despite this success, foam application in NFRs is still much less understood than in unfractured porous media. In this dissertation, we aim to expand our understanding of foam in fractures through an experimental approach. To this end, we create four 1-m-long, 15-cm-wide glass model fractures (Models A, B, C and D) with different roughness and hydraulic apertures. Each model consists of two 2-cm-thick glass plates. The top plate is smooth and the bottom plate is roughened on the side facing the top plate. Between the two plates is a slit-like channel representing a single geological fracture. Model A has a roughened plate with a regular roughness. Models B, C and D, with increasing hydraulic apertures, use the same roughened plate with an irregular roughness. We profile the roughness of the roughened plates and study the aperture distribution of the model fractures to characterize the geometry of the model fractures. With local hills (maxima of height) and valleys (minima of height) on the roughened plates, the distribution of aperture of model fractures can be represented as a 2D network of pore bodies and pore throats. In the experiments, we inject pre-generated foam into the model fractures. We study foam behavior after foam flow reaches steady-state. As our models are transparent, we use a high-speed camera to directly visualize and record images of foam in the model fractures. Using ImageJ software, we analyze foam images to quantify the properties of the foam.

Enhanced oil recovery (EOR) seeks to improve the recovery of oil from existing mature oil fields. It targets the oil left behind after conventional recovery by natural reservoir drive and water injection. The injection of surfactant polymer chemicals can enhance oil recovery by reducing the interfacial tension, allowing more oil to be released from its host rock and improving the flood conformance.
In this study, the principles and parameters of chemical surfactant polymer EOR mechanisms, which mobilise, displace and transport residual oil (i.e. build an effective oil bank) after water injection were investigated. The current understanding of when, and under what conditions, an oil bank is formed and maintained is limited. This is relevant in core-flow experiments that need to be appropriately interpreted and scaled, from the centimetre to the field scale, in various steps. Various factors that influence the dynamics of building a stable oil bank were evaluated, using an extensive core-flow experimental study with the aid of computed tomography scanning....

Rapid injectivity decline is frequently observed during injection in unconsolidated sand reservoirs. Field data suggests that hydraulic fracture processes are directly or indirectly related to this injectivity decline. Conventional fracture theories do not apply to unconsolidated sand since this material has little to no cohesion and tensile strength. The main fracture mechanism hypotheses are shear failure of the zone ahead of the fracture tip and fluidization. For both mechanisms, a fluid pressure high enough to initiate and propagate the fracture is required. The fluid pressure is dependent on the injection rate, fluid viscosity and permeability of the formation. Unconsolidated sands have a high permeability, thus under normal waterflood conditions a high injection pressure is not expected. Three main impairment mechanisms leading to the injectivity decline have been identified based on field evidence and previous work:

-Plugging
-Wellbore fill
-Resorting of grains and finer particles

Plugging results from the infiltration of fines originating from the injection fluid, crossflow or drilling mud. The external and/or internal filter cake can locally reduce the permeability of the formation. During surface shut-ins, backflow and/or crossflow can occur leading to the infiltration of solid particles and fluids into the wellbore. This reduces the leak-off area of the well. Lastly, resorting of grains and finer particles can result in a denser packing of the reservoir. The dynamically mixing of particles can lead to lower permeability regions.

Research goal
The main goal of this research is to develop a better qualitative and quantitative description of the fracturing process and the impairment mechanisms causing the observed injectivity decline. This thesis comprises of the first phase of this research, focusing on the capabilities of the equipment to create and detect fractures under waterflooding conditions. What makes this research unique is the use of low viscosity fluids, to mimic field conditions. Other work often involves the use of efficient fracturing fluids that have a high viscosity and/or good filter cake building capabilities to minimalize the leak-off. Next to that, injection of fluids is performed live in a CT scanner. This allows the visualization of fractures or low-density regions through density distributions in three dimensions over time.
Equipment
Injection takes place in a high-strength aluminium vessel with a sample volume of 3.84 dm3. See images 2.1 and 2.2 of an overview of the setup and pressure vessel. Axial and radial pressure can be controlled independently up to 20 MPa. A pore fluid system records the outflow mass and provides a fluid pressure on the sample. The sample consists of a very fine, very well sorted sand with a permeability around 5 Darcy. The main injection fluids are water and Fluorinert FC-770. This is a high density, low viscosity fluid that is used to visualize the preferential flow path of the injection fluid in the CT scanner.
Results
Fractures have been successfully created using a high viscosity fluid during the first experiment. The goal of that experiment was to test the setup and the equipment. The fractures were created at an injection pressure of 38 MPa and were up to 1 cm long and 2 mm wide. Experiments 2 and 3 were performed in the CT scanner with the use of Fluorinert as the injection fluid. The infiltration zone of this fluid was clearly visible but no fractures were created. Sand infiltration in the injection tube leaded to a number of problems during the experiments. Experiments 4 and 5 added fines to the injection water. Quartz powder was used in experiment 4 and bone meal in experiment 5. The fines leaded to a gradual increase in injection pressure, but did not lead to a higher density in the CT scans. No fractures were observed but low-density regions in front of the perforations were created during both experiments as a result of backflow. Experiment 6 introduced the use of internal pressure sensors in the sample and used a sample created with two sands and Kaolinite, a non-swelling clay. During two high flowrate injection cycles, the clays migrated away from the near wellbore region, leaving behind lower density regions.
Conclusion & future work
Creating fractures with low viscosity fluids in a laboratory environment has proven to be difficult. No fractures have been created throughout the low viscosity experiments. Several impairment mechanisms that were identified in the field have also been observed in the experiments. This thesis forms a solid basis for the next research phase to investigate these impairment mechanisms more closely. By lowering the confining stresses, increasing the flow rates and decreasing the sample permeability, there is a good probability that fractures can be created with this equipment in future work.

After a waterflood the oil saturation is (close to) the irreducible oil saturation, wherein oil in a porous medium is dispersed over the pore network in unconnected droplets due to snap off. In a chemical flood, the surfactant reduces oil-water interfacial tension and liberates the trapped oil droplets. These mobilised droplets coalesce into a greater body of oil, the oil bank. The surfactant-polymer and polymer slugs, with relatively high viscosity, act as displacing agents with piston-like displacement in an ideal scenario.

In this study, these oil banks are studied in core flood experiments using Fontainebleau sandstone cores of varying lengths and one 1m Bentheimer Sandstone core. In these core floods the effects of certain parameters on the oil bank behaviour are examined. The parameters range from rock properties such as permeability and core length, to fluid properties such as optimality of the surfactant to viscosity of the surfactant-polymer and polymer.

During the Paris climate convention, goals have been set to counter global warming and work towards a sustainable future. An energy source which has been researched more intensely the past years is HT-ATES - High Temperature Aquifer Thermal Energy Storage - system. This technique makes it possible to remove the heat pump from conventional HT-ATES energy sources and utilize waste heat or heat from sustainable sources. This paper discusses the robustness a HT-ATES triplet system. A case study is being done to test the triplet system in the present and with different climate scenarios in 2050. The triplet system consists of three storages instead of two as in conventional aquifer thermal energy storage systems. This third storage serves as a temporary storage and minimizes heat loss. With this system, the heat pump can be removed, creating a completely durable thermal energy storage system. The different scenarios show the possible effects of global warming. The system is tested in various climate scenario to see if it is robust and what the effect of global warming is on such a system will be. The results show that global warming indeed has a big impact on the functioning of a triplet system. These problems can be tackled by evaluating the climate at the location of construction of a triplet system. With this evaluation, an optimal design of the triplet system can be made. The number of solar panels and dry coolers can be optimized. Also the storage temperature inside the storages can be optimized for the present climate.

The main scope of the work related to the physical and dynamical processes associated with the injection of carbonated water in porous media. Carbonated water flooding is an alternative for traditional CO2 flooding. Both methods have the potential to recover any oil left behind after primary and secondary recovery while storing CO2 at the same time. The advantage of Carbonated Water flooding as compared to CO2 flooding is related to the high buoyancy of CO2 that results in gravity separation if the CO2 is not dissolved in water. This results in sub-optimal flooding of the reservoir and possible leakage of CO2.

Burning oil shales contribute to CO2 emissions. The spatial distribution pattern shows that these _res occur in areas with moderate or dry climates. This paper investigates the mechanism behind the burning oil shales. The first part includes an overview of the geological setting, Fieldwork results and petrophysical analyses. Based on these settings, we defined a horizontal fractured structure above and below the shale beds and vertical fractures with spacing varying from 10{30 cm. The matrix in between is oil shale with a kerogen content of 35% up to 70 %. The oil shale contains lenses of pyrite. Several dynamic models, based on this fractured oil shale structure, have been developed to illustrate aspects leading to enhancements or extinction of oil shale fires. Natural convection supplies air (oxygen) to sustain combustion. Air can penetrate into the matrix, mainly to the highly fractured structure, to react with fuel. The presence of oxidising pyrite may trigger the fire. Favourable conditions for oil shale fires are dryness, mostly during the summer, and a heat source.