The increasing global demand for energy has necessitated the exploration of untapped potential energy resources. Unconventional oil reservoirs present a significant opportunity for development through various enhanced oil recovery (EOR) methods. Among these methods, the huff’n’puff scheme using Carbon Dioxide (CO2) EOR has emerged as a potent technique, considering both productivity and its impact on global warming. Unlike water injection, CO2 EOR exhibits high injectivity potential in tight formations, making it a promising approach.
This thesis focuses on investigating the performance of CO2 EOR in unconventional oil reservoirs using the huff’n’puff scheme through a comprehensive reservoir simulation study based on an open-source geological model. The study evaluates the effects of key parameters on oil production, including injection rate, injection time, soaking time, diffusion coefficient, and well completion.
The simulation results demonstrate that CO2 EOR can effectively enhance oil recovery from unconven- tional oil reservoirs. Specifically, the study reveals that implementing CO2 EOR increases cumulative oil production by 27% after 20 years compared to natural depletion cases. Furthermore, when incorporating a two-year primary recovery period, cumulative oil production is further elevated to 45%. By implementing the findings from the sensitivity study, cumulative oil production can be increased up to 67% in the optimum case.
In terms of the influence of the tested parameters on oil production, the study identifies that higher injection rates and longer injection, soaking, and production times for each cycle improve oil recovery until reaching an optimum value. Additionally, extending injection period by 10 times in each cycle with the same CO2 injected volume improved cumulative oil production by 7% compared to fixed injection rate as a result of longer diffusion and dissolution time. Moreover, implementing bottom CO2 injection targeting bottom layers improves vertical sweep efficiency due to buoyancy forces. The study also highlights the importance of the diffusion coefficient, as higher values facilitate faster CO2 transport, resulting in higher oil recovery and reduced CO2 reproduction.
This thesis provides valuable insights into the design and implementation of CO2 EOR projects in tight oil reservoirs. It emphasizes the need for careful selection of optimal operating conditions based on specific reservoir properties and highlights the significance of the diffusion mechanism in CO2 EOR performance. The findings contribute to the development of more effective CO2 EOR strategies for unconventional oil reservoirs, addressing gaps in previous research. Moreover, the study’s outcomes have practical implications for improving the design and implementation of CO2 EOR projects in the field, ultimately leading to increased oil production.

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.

In order to supply the demand of oil, enhanced oil recovery (EOR) techniques are nowadays widely applied in the oil recovery industry to maximize reservoir sweep efficiencies. CO2-EOR method has been largely used in the petroleum industry for several decades, which can contribute to the reduction of global greenhouse gas emission through CO2 sequestration in geological formations besides the elevation of oil recovery levels. Conventionally, CO2 is implemented as a continuous flooding scheme. But CO2 flooding is prone to unfavorable displacements, viscous fingering, gravity segregation and early breakthrough due to the high mobility ratio, low viscosity and low density of CO2. A method to overcome these problems is the alternation of water and CO2 slugs. This method, better known as water alternating gas (WAG) injection, is widely applied through the field. But despite the successes of the WAG injection scheme, the method still suffers from a relatively poor mobility ratio and gravity override. In this experimental study, the performance of the polymer assisted water alternating gas (PA-WAG) EOR method is examined. This method makes use of the high viscosity of the polymer solution in combination with immiscible CO2, to improve the improve the mobility ratio, volumetric sweep efficiency as with that the ultimate recovery of the WAG process. For the polymer, a specially modified polymer is considered, which uses the ATBS (2-acrylamido-terbutylsufonic acid) addition to HPAM in order to improve the stability of the polymer under reservoir conditions. In this thesis, the displacement and recovery performance of the ATBS-modified HPAM polymer is studied via a series of core-flood experiments and the stability is tested via polymer aging in the presence of CO2. The results of this work
have shown that the addition of the ATBS-modified HPAM polymer to the water in the WAG method increased the recovery by 10% over the normal WAG injection, by improving the mobility ratio and displacement efficiency. By implementing the PA-WAG on a carbonate rock saturated with crude oil, a base line experiment with regarding reservoir simulated recovery was established, with a recovery of 76%. The stability test under the presence of CO2 showed that the dissolved CO2 impacts the polymer viscosity. After the initial decrease in apparent viscosity to 54% of the original viscosity, the ATBSmodified HPAM polymer was able to recover its viscosity to 84% of its original apparent viscosity after 29 days of aging. These results were achieved under full saturation of the polymer solution with CO2 . In addition, the impact of CO2 at PA-WAG flooding CO2 concentrations was evaluated, which showed now degradation with the exposure to CO2. The study concludes that the ATBS-modified HPAM polymer performs excellently in the PA-WAG method for enhanced recovery, significantly outperforming the WAG injection method.

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 6B2. Each experiment had a specific concentration of 6B2 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.

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 is a commercially viable chemical enhanced oil recovery (cEOR) method. It includes the injection of water-soluble polymers into a reservoir to improve the drive water viscosity and consequently to increase the sweep and displacement efficiency of the water. Despite the success in both laboratory and field applications, there are still some challenges associated with the application of polymers for cEOR. The first challenge is that the implementation of conventional polymers used for cEOR at high salinity, hardness, and temperature reservoirs is difficult and costly because of the viscosity loss and polymer precipitation at these harsh conditions. The second challenge concerns the injectivity of the polymers. Long polymer chains tend to block the small pores which leads to a time-dependent injectivity decline. This thesis investigates the potential solutions to address these two challenges in order to improve the performance of water-soluble polymers.

A large fraction of hydrocarbons is recovered from gas condensate reservoirs. A major production challenge from gas condensate reservoirs is condensate dropout, as condensate liquid saturation will build up due to drawdown below dewpoint level. Condensate Gas Ratio (CGR) decrease during production is a clear indication of condensate dropout, which reduces well deliverability. Determining the well productivity index (PI) and methods to optimize productivity is paramount to the industry. The aim of this research is to investigate fluid phase change behavior during depletion in a hydraulically fractured well in an extremely low-permeability gas condensate reservoir. Here it is considered the case where condensate dropout occurs over a large volume of reservoir, rather than just near the fracture face (condensate banking). Reservoir simulation with local grid refinement (LGR) was used to understand this phenomenon and its impact on well PI, and to quantify pressure drop in the reservoir as a result of condensate dropout. The relationship of condensate dropout, pressure drop, gas rate and reservoir permeability are investigated by comparing conventional tight reservoirs, and very tight unconventional gas condensate reservoirs, both of which are produced with propped fracture stimulation. A commercial 3-D compositional simulator with LGR around the fracture was utilized to simulate such a reservoir with both synthetic and field data by observing the compositional changes (i.e., C1, C2, C3,..) in hydrocarbon content over time and distance from the fracture face, and the results were used in turn to generate more realistic production profiles over time. Additionally, a comprehensive discussion of the model assumptions and limitations is also included. The result shows a significant change in the composition and relative permeability to gas in the reservoir as the pressure declines during depletion. The simulation is done in two parts: synthetic and field data history matching. The results illustrate the complications in understanding the PI evolution of hydraulically fractured wells in “unconventional” gas condensate reservoirs and shows how to correctly evaluate fracture performance in such a situation. This research includes a review of several techniques and methods to calculate the occurrence of condensate at various distances from the well and fracture and includes a sensitivity analysis of the different parameters and how they affect well PI over time and ultimate recovery of gas and condensate. This findings and novel approach of this study aim to more accurately predict post-fracture performance and provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs.

Water injection is widely used in the petroleum industry for the increase of hydrocarbon recovery or disposal of wastewater. Water production and injection are the primary mechanisms in Geothermal Energy. Both include injecting water into a porous formation under matrix injection conditions. While maintaining water injection is vital in these branches in the industry, so is the occurrence of formation damage (FD) due to suspended contaminants or brine incompatibility. Suspended particles in injection water are retained or deposited due to the creation of an External Filter Cake (EFC) or Internal Filter Cake (IFC) impairing the permeability. Consequently, FD results in Water Injectivity Decline (WID). In most cases, the negative impact on injectivity translates into operational and economic targets not being met. WID, as a result of FD, is highly connected to the Water Quality (WQ) of the injection water. A new approach to water quality (WQ) testing is proposed which suffices as a bridging application of membrane filtration and core flooding. To establish a foundation for this method, tests are conducted by performing particle-laden suspension injection experiments with porous outcrop sandstone 8 mm thin discs utilizing the ‘Con-vergence Hydra’. An experimental study is conducted investigating the effect of water quality (WQ) on formation damage, using dilute (20-100 mg/l) Baracarb2 (CaCO3) particle suspension as a model contaminant. Baracarb2 is tested for particle size distribution, mineral content and stability within synthetic brine (resembling Seawater). Subsequently, suspension flow experiments are conducted on porous thin discs (Bentheimer & Berea sandstone) as well as membrane filters (MF0.45μm). As performing suspension injection test with porous thin disc test utilising the Hydra has not been done before, reproducibility of the experiments is tested. The reproducibility of performing experiments utilising the Hydra is high, with very little difference between the experimental outcomes.Varying WQ within each different porous media type illustrates remarkably similar trends. Moreover, it is demonstrated that by performing a similarity curve collapse, a master curve is obtained for each porous medium type which scales with suspension concentration for Baracarb2. The damage mechanisms explaining this master curve all demonstrate a linear permeability impairment in the early part of the experiments. Subsequently, a linear impedance trend is observed where it is assumed that cake filtration is dominant. The latter is demonstrated by calculating the Modified fouling Index (MFI), which shows a linear dependency with suspension concentration. SEM imaging and Micro-CT scan images substantiate the damage mechanisms hypothesized from the pressure and rate data.The Con-vergence Hydra utilising porous thin discs has great potential for on-site testing which allows fast and reliable results on permeability impairment, i.e. formation damage. Subsequently, monitoring of the water quality can be done by performing MFI analysis during cake filtration. 

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.

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.

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.

Chemical Enhanced Oil Recovery (CEOR) methods can increase the oil recovery of a reservoir to more than 60% of the volumes originally in-situ. Typical oil recoveries range from 20% to 40% of OIIP under traditional primary and secondary recovery stages. The understanding of the mechanisms that control such complex processes is essential considering the continuously growing worldwide energetic demand. History matching of core flooding experiments data through numerical modeling is a powerful tool to understand the physical parameters and mechanisms that control the flow of fluids in novel recovery strategies as Foam-Assisted Chemical Flooding (FACF) in which the effects of oil/water interfacial tension generated by surfactant are combined with mobility control provided by foam.
This report presents the mechanistic modeling study of seven experiments on different core flooding techniques including continuous gas injection, Water-Alternating-Gas injection (WAG), surfactant injection and Foam-Assisted Chemical Flooding (FACF) on Bentheimer sandstone cores. CT scan images were acquired to monitor the evolution of saturation distributions, starting from the primary drainage stage. A 1D model was built for each experiment to history match the saturations revealed by the CT scan imaging through the cores at different pore volumes injected, pressure drops, production fractions, and oil recovery. Good agreement between simulation results and experiments was obtained, with minor mismatches in breakthrough times (0.04 ± 0.02 PVI) for some experiments.
For the history match of primary drainage and forced imbibition, the parameters of the Brooks-Corey equation for calculating relative permeabilities were obtained from a regression analysis on the available observed data. Actual residual saturations were lower than the average saturations reported at the end of each flooding stage.
History-matching of the continuous gas injection at waterflooding residual oil saturation and WAG at connate water saturation experiments demonstrated that the initial water saturation in secondary and tertiary gas injection strategies is a parameter that greatly controls gas mobility. Gas trapping and its effect on the flooding was confirmed for the WAG experiment.
The mechanistic modeling of surfactant injection at under-optimum salinity conditions showed that the geochemical modeling to determine initial ionic concentrations in the aqueous phase can be neglected in absence of naphthenic acids in the oleic phase, even when alkali is present in the solution. The shape and size of the oil bank formed after mobilization of residual oil are controlled by the proper numerical representation of the phase behavior in the oil/microemulsion system, whilst other features as oil bank velocity are controlled by surfactant adsorption. Relative permeability curves at low trapping numbers (forced imbibition) and high trapping numbers (under-optimum salinity conditions) were obtained.
Finally, history match of the drive foam in FACF led to the conclusion that the local equilibrium model for foam model implemented in UTCHEM may not be able to cover the entire range of possible mechanisms controlling the foam formation, specifically, the mechanism by which foam is generated due to increase in interstitial velocity and local pressure drop in zones of reduced effective porosity near a previously formed oil bank.

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.

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).

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.

Synthetic polymers, in the emulsified form, have been utilized for enhanced oil recovery applications by using saline make-up water. However, there are concerns that have been raised about their injectivity. The large entangled polymer chains can clog the pore throats, giving a tendency to cause injectivity reduction. In this study, processing techniques were used to condition an acrylamide-based copolymer inverse emulsion system at a salinity of 50,000 ppm TDS before being injected into porous media. The investigated polymer solution contained 4,000 ppm active emulsion-polymer and 2,400 ppm surfactant, providing a zero-shear rate viscosity of 13 mPas. Shearing with two agitators, a disperser and Ultra-Turrax, at different intensities and pressure-driven flow into a thin capillary reduces the size of the largest polymer and disentangles the polymer chains while maintaining its viscosifying power as much as possible. Subsequently, the filtration ratios (퐹푅) with optimum between 1–1.2 were determined by performing filtration tests in a 1-micron polycarbonate membrane to evaluate the plugging behavior. This was followed by sand-pack flooding tests of differently sheared solutions in order to investigate the impact of pre-conditioning on injectivity.
Bulk experiments enabled the establishment of master curves showing viscosity and screen factor dependences on accumulated energy during pre-shearing, regardless of shear origin. The injected unsheared polymer solution has an 퐹푅 of 1.6 and an injectivity gradient, e.g. ratio of resistance factor over 10 pore volumes, of 2.4. All injected pre-conditioned solutions have an 퐹푅 in the optimal range between 1 to 1.2. By imposing 15 MJ/m3, the disperser-sheared solution improves the injectivity by decreasing the injectivity gradient to 1.3, while the viscosifying power is reduced by 2% and the screen factor by 30%. To reach the same injectivity gradient of 1.3 with Ultra-Turrax, 31 MJ/m3 were imposed, which reduces the viscosity and screen factor by 11% and 44% respectively. The sheared solution into a capillary imposes 50 MJ/m3, giving an injectivity gradient of 2.7. Both viscosity and screen factor are reduced by 19% and 53% respectively. This indicates that the injectivity performance is shear-origin dependent and the resulting polymer structure, when sheared through contractions, has a different alignment as compared to shearing with the agitators, the disperser and Ultra-Turrax.
In conclusion, the rheological dependencies of sheared polymer solutions form a master curve dependent of accumulated energy during shearing with different shearing devices. Further, the proven beneficial impact of pre-conditioning with agitators before injection enables a better utilization of polymer flooding operations by reducing the risk of pore plugging.

It is well known in the oil & gas industry that mature oil fields with a water drive produce increasing volumes of oily produced water which require treatment and efficient disposal. It is a major concern of all waterflood operations now in the industry, to adopt cost effective and environmentally sound water disposal systems. Re-injection into the subsurface has been chosen to be a potentially attractive option from environmental regulations view point, but to become the preferred alternative for produced water disposal, re-injection (PWRI) must also be economical and should not incur excessive risk in form of injectivity decline and damage to the formation. In this study, a semi-analytical model of contaminated water injection under fracturing conditions, including the effects of damage mechanisms over time is developed, that couples the reservoir engineering and fracture mechanics aspects of the problem. The main features of this model are finite fracture conductivity, external filter-cake build-up on the fracture face, internal plugging at fracture tip by injected solids, backstress resulting from pore pressure inflation (poro-elastic stress), backstress resulting from formation cooling (thermo-elastic stress), and fracture propagation. The most important characteristic is that the fracture is of finite conductivity due to fracture fill up by total suspended solids and oils in injected water. This is what differentiates this model from conventional waterflood induced fracturing simulators. This model is an extension to Koning’s model for waterflood induced fracturing, where fracture is of infinite conductivity. This model is largely based on work of Hoek et al. for finite conductivity fracture. This model incorporates a rectangular fracture that fully penetrates a permeable layer bounded by impermeable layers on top and bottom. The fracture is surrounded by three elliptically shaped zones, formation damages caused are included which are critical for fracture propagation, and the primary objective is to predict long term fracture growth and well injectivity. The governing Equations for fracture propagation are based on four fundamental physical phenomena which are fluid leak-off from the fracture into the formation, fluid flow inside the fracture, poro-elastic and thermo-elastic backstress on the fracture face and fracture propagation into the formation. The novelty of the new simulator is the ability to model waterflood induced fracture including all kinds of damage mechanisms, and accurately predict fracture propagation quickly.

Oil & gas wells are plugged and abandonment when have reached the end of their production life-cycle or are discovered dry during exploration. It is estimated that currently 20-30 million oil & gas wells are waiting to be permanently decommissioned worldwide. The maturation of the oil \& gas industry will only continue to increase the number of wells to be abandoned going forward in to the future. Although effective and efficient, the conventional use of cement for the plug & abandonment of wells proves to be associated with certain limitations. Bentonite is being considered as an alternative material for plug and abandonment. Bentonite is a clay which is known for its high swelling capacity, with a potential volume increase up to 300% upon hydration. Additionally, saturated bentonite has a low water permeability and a self-healing capacity. Evaluating bentonite as an alternative sealing material is important to determine its applicability to oil & gas wells. An abandonment plug must be able to mechanically withstand pressure differentials resulting from remaining or recharged reservoir pressures whilst preventing the resulting fluid migration, ideally for an indefinite amount of time. An assessment of the different gas migration mechanisms through a bentonite plug is considered in this study. Four possible gas migration mechanisms through bentonite were identified: advective-diffuse, visco-capillary, dilatant pathway formation and macroscopic tensile fracturing flow. Two of these mechanisms are relevant for the evaluation of a bentonite plug; visco-capillary and dilatant pathway formation flow or a combination of both. From experimental work, it has been observed that gas migration commences at a differential pressure which is in the same range as the swelling pressure produced during the hydration of the bentonite plug. The magnitude of the plug swelling pressure is influenced inversely by the free swelling space and proportionally by the dry density of the bentonite plug. When hydrating bentonite material is fully confined, the gas breakthrough pressure is determined by the dry density of the bentonite plug. In the case of a plug comprising of compacted bentonite pellets a maximum dry density of 1000 kg/m3 can currently be produced; this results in gas breakthrough pressures in the range of 2-5 bar. Experimentally it was observed that a permeability of 20 nD at a pressure differential of 20 bar was observed in a bentonite plug comprising of hydrated granular bentonite material; a permeability which is as low as a cap-rock. This result highlights the potential of bentonite as a sealing material, but practical operational considerations have to be taken before this can be achieved in oil \& gas wells. These results indicate that it is currently not practical to use bentonite as pressure bearing abandonment plug. Further knowledge is required regarding; the pressure-time dependency of the gas permeability; sensitivity of the bentonite swelling pressure to water salinity; and the impact to the bentonite plug quality over prolonged exposure to high temperatures.

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.