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

In 1949, Toms (Toms B.A., (1949, 1977)) observed that small amounts of a drag reducing agent (DRA) could cause a considerable drag reduction in turbulent pipe flow. In application of polymer enhanced oil recovery, degradation of polymers in the supply lead could cause clogging. It was, however observed that surfactants at sufficiently high concentration also showed drag reduction without the problem clogging. A DRA reduces the energy loss by friction and unstable flow, thus improving injection throughput with the same pressure pump and thereby reducing the exergetic pumping costs. This study investigates experimentally the drag reducing capacity of surfactants and compares it to the drag reducing capacity of polymers. For the experiment, a set-up consisting of a pump, a coiled test tube with a length of 1.48 m and an inner diameter of 0.5 mm and pressure gauges is built. The diameter of the coil is 12.5 cm. We use a pump capable of injection up to 200 ml/min. The pressure drop is measured between the entrance and end of the tube. The injection rate is varied between 1 and 200 ml/min, roughly corresponding to Reynolds numbers between 50 and 10,000. The additives are dissolved in brine with a 33,000 ppm salt concentration. The viscosity of the solution is dependent on the concentration of the DRA. The ratio of the measured pressure drop with only brine and the pressure drop with the DRA solution was used to calculate the drag reduction (DR) factor, as from a technical point of view we are only interested whether adding DRA reduces the drag with respect to the original brine solution. From an academic point of view, we remark that for low concentrations the viscosity enhancement due to the presence of the DRA is negligible. As polymers we use xanthan (a biopolymer), and a synthetic emulsion polymer based on polyacrylamide. Maximum DR factors are 23% for xanthan at 90ppm and 32% at 90ppm for the synthetic emulsion polymer. DR only occurs at turbulent conditions. Three types of surfactants, each from a different branch of surfactants are used in this study. The surfactants used are AOS {훼-Olefin Sulfonate}, CTAB {hexadeCylTrimethylAmmonium Bromide} and APG {Alkyl PolyGlucoside} which are a cationic, anionic and a nonionic surfactant respectively. The surfactants did not show any DR at (for DRA applications) high concentrations up to 20.000ppm. Addition of Sodium Salicylate (NaSaL) to CTAB with a 1:1 ratio led to a maximum DR of 33% at 2500 ppm concentration. Several pressure gauges have been installed along the test tube in order to observe how the pressure drops along the tube, how the DRAs affect these pressure drops and at what location of the test tube the DR factor is the highest. It is found that xanthan has the same DR factor at each location of the test tube, the emulsion polymer has a decreasing DR factor as the distance from the inlet of the test tube increases and the CTAB+NaSaL DRA has an increasing DR factor as the distance from the inlet increases. The DRAs are sheared using a constriction in the flow loop while the degradation is monitored. It is observed that xanthan is less susceptible to degradation in comparison to the emulsion polymer due to its more rigid chemical structure. But xanthan and the emulsion polymer would be inefficient to use in looped flow systems as they are affected by degradation. The CTAB+NaSaL DRA on the other hand shows no degradation meaning that the micellar rod-like structures that give the DR effect are being repaired when the shear force is being removed. However, for surfactants higher concentrations (1000-2500 ppm) are required.

Salt caverns formed by solution mining may cause soil subsidence, because the surrounding adapts to fill the void (cavity) created in the strata. The cavern volume is hence not only a function of salt extraction (estimated from mass balance) but also a function of salt creep. The cavern size can be measured by sonar, but a less costly way would be to correlate cavern volume to cavern compressibility. The size of the cavern can be obtained by a compressibility test. The compressibility test consists of injecting brine or fresh water into the cavern, causing a pressure build-up. The pressure increase depends on the cavern volume and compressibility. Bérest et al. (2006) [1] derived an equation that expresses the pressure response to injection of a volume V of fresh water. The equation includes creep that can be derived from a separate geometric creep model that relates the strain to the stress history using the Norton-Hoff law for describing an Arrhenius type of response model, and thermal expansion effects influenced by the geothermal temperature. It also considers Darcy flow and leakage through the permeable salt cavity. This thesis investigates the sensitivity related to the various mechanisms in the Bérest and Van Sambeek (2005) model. It also extends the model by introducing chemical dissolution of salt effects and taking into account the impact of the sump (insoluble precipitates at the bottom of the cavern). We state the model equations and solve them for an example of interest. We can also compare the calculated pressure response to the results of a pressure test. In this pressure test a given volume of fresh water is injected above the sump and produced at the top of the cavity. The produced salt concentration is also one of the parameters measured in the test. There are at least two widely used methods to obtain or predict cavern size of active salt solution mining caverns, namely sonar surveys and leaching simulators. However, these data can be flawed due to uncertainties of the methods and the accuracy of measuring devices like flow meters. The compressibility test can then be used as an additional survey method. The test execution is simple and inexpensive, making it possible to be performed more frequently than a sonar survey. The cavern volume is obtained from a compressibility test data by using a solution that includes not only the injection volume, but also volumes introduced by other phenomena. These other phenomena are caused by thermal, hydraulic, mechanical, and chemical influences. Previous work has attempted to introduced solutions incorporating these influences for idle caverns. The proposed solution incorporates these effects in an active leaching salt cavern. It also introduces the impact of sump (insoluble on cavern bottom) to be included in the model. The proposed solution is then tested against field data. The work here differs from previous work that it presents a comprehensive description of the various methods used in the literature and practice. Where current models predict cavity volumes with a mean absolute percentage error of 33% (Thiel’s method for BAS3O) to 127% (Bérest et al. for BAS4) for the studied caverns (BAS3O and BAS4), the model here, which includes the presence of insoluble particles, and a well-established creep model is able to predict cavity volumes to an accuracy of 33% (proposed model for BAS3O) to 12% (proposed model for BAS4).

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

Global energy transition is crucial in mitigating climate change. Numerous initiatives are being taken globally to achieve a carbon-neutral energy system. These goals require a complete shift from non-renewable energy sources to renewable sources like geothermal energy. These renewable sources of energy have to be constantly improved in order to maximise their efficiency and to ensure the cleanest possible source of energy. One of the challenges in geothermal energy is degassing of geothermal fluids. These fluids contain a lot of minerals and chemicals dissolved in them that are at equilibrium at a certain pressure and temperature. When there is change in this pressure and temperature during extraction, the equilibrium condition changes and the gases dissolved in the fluids degas. These gases then get trapped in pores and decrease the efficiency of extraction of these fluids. They might also prove harmful to the environment due to release of greenhouse gases from the geothermal fluids. The aim of this experimental research project is to visualise the degassing of geothermal fluids and understand the conditions and affect of degassing on the core. The experiments were carried out by injecting either tap water or brine at a set flow rate of 15ml/min and different concentrations of 𝐶𝑂2. Each experiment had a specific concentration of 𝐶𝑂2 which was injected simultaneously with brine at a certain back-pressure. Then the back-pressure was lowered gradually and when the fluid de-gassed it was allowed to reach steady state and a scan of the core was taken. Throughout the experiments pressure measurements were taken along the core.

Foam-assisted chemical flooding (FACF) is a novel enhanced oil recovery (EOR) methodology that combines the injection of a surfactant slug, to mobilize previously trapped residual oil, with foam generation for drive mobility control, thus displacing the mobilized banked oil. The main goal of this study concerns the understanding of oil mobilization and displacement mechanisms that take place in a FACF process. At first, in order to promote understanding of the incremental benefits FACF can provide one with, we get ourselves familiar with immiscible gas flooding and water-alternating-gas (WAG) injection. Subsequently, we study the effect of aqueous phase salinity, drive foam quality, and method of drive foam injection, on the oil mobilization and displacement processes in FACF, at both model-like conditions and in a reservoir setting. We present novel insights, on the dynamic physical processes that take place within the porous media during FACF, which could only be obtained through the assistance of a medical CT scanner. Moreover, in order to identify the main controlling parameters that determine incremental oil recovery in WAG and FACF, we develop several mechanistic models for the aid of history-matching laboratory observations.@en

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.@en

Energy storage is increasingly becoming a possible solution worldwide to aid the energy supply and demand. The objective of this study is to determine whether thermal energy storage can be effectively and efficiently achieved by ways of electromagnetic (EM) radiation. To serve this purpose, an experimental setup was designed in order to subject core flooding experiments to EM heating using a MW source. Temperature data is obtained and used to construct temperature profiles as well as energy absorption and storage profiles. The experiments vary from EM radiation under no flow conditions to experiments inducing flow in order to determine the effect of flow on energy absorption and storage amounts. The results obtained show that a significant amount of energy is absorbed by the core and that the introduction of flow at the chosen flowrates during EM heating does not diminish the energy absorption ability of water inside the core. Flow does however increase the rate of energy decline within the core when EM heating is stopped thus reducing the amount of energy stored. Nevertheless, around 40% of the energy absorbed after 150 seconds of EM heating is stored in the core after a cooling period of 60 minutes. This amount declines significantly when flow in implemented throughout heating and cooling. Even though the experimental setup performed accordingly, the large amounts of energy losses are an area that should be subject to improvement. When this technology is implemented in reservoirs or aquifers, the MW antenna is placed in the pay zone. This results in lower energy losses due to the over- and underlying formations functioning as insulation. Subject to improvements, this study concludes that EM stimulated core flooding is a legitimate and viable technology with significant potential for thermal energy storage purposes."

Polymer flooding plays an essential role in Enhanced Oil Recovery by means of achieving a more favorable mobility ratio through increasing the viscosity of the displacing phase and thus improve macroscopic sweep efficiency. Conventional polymer, e.g., hydrolyzed polyacrylamide, dissolved in brine at high-salinity and high-temperature can be subjected to thermal degradation due to hydrolysis of amide group to acid which can result in precipitation driven by the interaction between acid groups and divalent ions, so these processes lead to loss in viscosifying power of drive fluid, thereby hindering polymer efficiency. To overcome these challenges associated with polymers at harsh conditions, a new hybrid dispersion consists of silica nanoparticles and hydrophobically modified polyacrylamide was proposed. This study aims to investigate the adsorptive and transport behaviour for this novel combination using rheological measurement and core flood experiments. Two-phase experiments were conducted to reveal the potential ability of the dispersion in increasing oil recovery compared to water flooding. Three different systems are used in this study, first, polymer solution at a concentration of 500 mg/L, second, nanofluids containing only SiO2 particles with a concentration of 5,000 mg/L and the third system is the dispersion of silica nanoparticles at 5,000 mg/L and PAM-98 at 500 mg/L. Rheological tests and single-phase experiment results showed that introducing silica nanoparticles to polymer solution led to the bulk viscosity enhancement and improvement in the adsorptive and transport behaviour of nanofluid. However, two-phase experimental results showed no increase in incremental oil recovery at the given study conditions, since water flooding was highly efficient.

CO2 flooding is a widely employed method for enhancing oil recovery. However, it faces challenges stemming from differences in viscosity and density between oil and CO2, leading to poor sweep efficiency. This can result in issues such as viscous fingering, channelling, and gravity segregation, causing premature breakthroughs and excessive gas production. To address these concerns, the Polymer Assisted Water Alternating Gas (PA-WAG) technique combines the advantageous attributes of CO2 flooding, such as solubility and displacement, with the effective mobility control provided by polymer flooding. This results in a chemically enhanced Water Alternating Gas (WAG) flooding approach. A study by van Wieren et al. (2022) delved into the effectiveness of PA-WAG in addressing CO2 flow challenges and improving sweep efficiency by conducting core-flood experiments. This work builds upon that study by employing numerical simulations to replicate the core-flood experiments. These simulations shed light on the fundamental physical mechanisms during the PA-WAG injection process while also facilitating the calibration of flow parameters for practical implementation on a larger scale. The primary goal of this study was to comprehensively model three distinct enhanced oil recovery (EOR) techniques: polymer injection, CO2 flooding, and PA-WAG, all applied specifically to the Bentheimer sandstone cores. The objective was to history-match CT (Computed Tomography) scan saturation data, observed pressure drops, and oil recovery. A 2-dimensional (2D) model was constructed for each experiment, with CT scan images used to allocate varying porosity and permeability values to individual grid blocks. This enabled monitoring saturation distributions from the initial primary drainage phase onward. In the history matching of the primary drainage phase, parameters for relative permeabilities were determined from the Brooks-Corey equation, leveraging CT scan saturation data. The scaling of relative permeabilities based on CT scan saturations effectively accounted for capillary end effects observed in the core-flood experiments. During the history-matching of the polymer injection process, it was demonstrated that polymer-specific parameters, as determined from experimental data, could effectively modify waterflood relative permeabilities, thereby reducing the mobility ratio and accurately capturing the advancement of the polymer front. The formation of emulsions towards the end of polymer injection led to a notable increase in pressure drop, necessitating the incorporation of a high Residual Resistance Factor (RRF) to accommodate permeability reduction. In the case of history-matching for the CO2 flood, the black oil model successfully replicated the process of immiscible gas injection. It aptly captured gravity segregation while utilising CT scan saturation scaled relative permeabilities to assess the impact on oil recovery. The study unveiled that the relative permeability of gas under immiscible conditions was relatively lower than in miscible and near-miscible conditions. Simulating the PA-WAG injection by combining polymer and CO2 models effectively reproduced the core-flood experiments. The study substantiated the role of gas trapping in reducing the relative permeability of gas as a function of injection time, consequently leading to heightened pressure drops during subsequent polymer slug injections. The study showcased the efficacy of integrating black oil models for polymer and CO2 injection to successfully simulate PA-WAG injection and achieve unity with core-flood experiments yielding valuable insights into the physical processes underlying the technique.