Reactions between CO2-charged brines and reservoir minerals might either enhance the long-term storage of CO2 in geological reservoirs or facilitate leakage by corroding cap rocks and fault seals. Modelling the progress of such reactions is frustrated by uncertainties in the absolute mineral surface reaction rates and the significance of other rate limiting steps in natural systems. This study uses the chemical evolution of groundwater from the Jurassic Navajo Sandstone, part of a leaking natural accumulation of CO2 at Green River, Utah, in the Colorado Plateau, USA, to place constraints on the rates and potential controlling mechanisms of the mineral-fluid reactions,under elevated CO2 pressures, in a natural system. The progress of individual reactions, inferred from changes in groundwater chemistry is modelled using mass balance techniques. The mineral reactions are close to stoichiometric with plagioclase and K-feldspar dissolution largely balanced by precipitation of clay minerals and carbonate. Mineral modes, in conjunction with published surface area measurements and flow rates estimated from hydraulic head measurements, are then used to quantify the kinetics of feldspar dissolution. Maximum estimated dissolution rates for plagioclase and K-feldspar are 2x10-14 and 4x10-16 mol·m-2·s-1, respectively. Fluid ion-activity products are close to equilibrium (e.g. DGr for plagioclase between -2 and -10 kJ/mol) and lie in the region in which mineral surface reaction rates show a strong dependence on DGr. Local variation in DGr is attributed to the injection and disassociation of CO2 which initially depresses silicate mineral saturation in the fluid, promoting feldspar dissolution. With progressive flow through the aquifer, feldspar hydrolysis reactions consume H+ and liberate solutes to solution which increase mineral saturation in the fluid and rates slow as a consequence. The measured plagioclase dissolution rates at low DGr would be compatible with far-from-quilibrium rates of ~1x10-13 mol·m-2·s-1 as observed in some experimental studies. This suggests that the discrepancy between field and laboratory reaction rates may in part be explained by the differences in the thermodynamic state of natural and experimental fluids, with field-scale reactions occurring close to equilibrium whereas most laboratory experiments are run far-from-equilibrium. Surface carbonate deposits and cementation within the footwall of the local fault systems record multiple injections of CO2 into the Navajo Aquifer and leakage of CO2 from the site over ca. 400,000 years. The d18O, d13C and 87Sr/86Sr of these deposits record rapid rates of CO2 leakage (up to ~1000 tonnes/a) following injection of CO2, but rates differ by an order of magnitude between each fault, due to differences in the fault architecture. Elevated pCO2 enhances rates of feldspar dissolution in the host aquifer and carbonate precipitation in fracture conduits. Silicate mineral dissolution rates decline and carbonate precipitation rates increase as pH and the CO2 charge dissipate. The Sr/Ca of calcite cements record average precipitation rates of ~2x10-6 mol/m2/s, comparable to laboratory derived calcite precipitation rates in fluids with elevated Mn/Ca and Fe/Ca, at cc of ~1 to 3. This suggests that far-from-equilibrium carbonate precipitation, which blocks fracture conduits and causes the leaking system to self-seal, driven by CO2 degassing in the shallow subsurface, can be accurately modeled with laboratory derived rates. Sandstones altered in CO2 leakage conduits exhibit extensive dissolution of hematite grain coatings and are chemically bleached as a result. Measurements of Eh-pH conditions in the modern fluid, and modeling of paleo-Eh-pH conditions using calcite Fe and Mn concentrations, suggests that the CO2-charged groundwaters are reducing, due to their low dissolved O2 content and that pH suppression due to high pCO2 is capable of dissolving and transporting large concentrations of metals. Exhumed paleo-CO2 reservoirs along the crest of the Green River anticline have been identified using volatile hosting fluid inclusions. Paleo-CO2-charged fluids mobilized hydrocarbons and CH4 from deeper formations, enhancing the reductive dissolution of hematite, which produced spectacular km-scale bleached patterns in these sediment.

The study of multiphase flow in porous media is highly relevant to many problems of great scientific importance, such as CO2 storage and enhanced oil recovery. Even though significant progress has been made in these areas, many challenges still remain. For instance, the leakage of stored CO2 may occur due to the capillary trapping failure of cap rock. Approximately 70% of oil cannot be easily recovered from underground, because the oil is held in tight porous rocks. Although CO2 storage and enhanced oil recovery are engineering processes at a geological scale, they are predominantly controlled by the transport and displacement of CO2 and reservoir fluids in aquifers and reservoirs, which are further controlled by wetting and fluid properties at pore scale. This work focuses on experimental investigations of pore-scale wetting and displacement of fluids and CO2 in porous core samples. Pore wetting, which has been measured based on contact angle, is a principal control on multiphase flow through porous media. However, contact angle measurement on other than flat surfaces still remains a challenge. In order to indicate the wetting in a small pore, a new pore contact angle measurement technique is developed in this study to directly measure the contact angles of fluids and CO2 in micron-sized pores. The equilibrium and dynamic contact angles of various liquids are directly measured in single glass capillaries, by studying the effects of surface tension, viscosity and chemical structure. The pore contact angles are compared with the contact angles on a planar substrate. The pore contact angle of a confined liquid in a glass capillary differs from the contact angle measured on a flat glass surface in an open space. Surface tension is not the only dominant factor affecting contact angle. The static contact angle in a glass pore also varies with liquid chemical structure. Viscosity and surface tension can significantly affect the dynamic pore contact angle. A new empirical correlation is developed based on our experimental data to describe dynamic pore wetting. The CO2-fluid contact angle in porous media is an important factor affecting the feasibility of long-term permanent CO2 storage. It determines CO2 flow and distribution in reservoirs or aquifers, and thus ultimately finally the storage capacity. CO2-fluid contact angles were measured in small water-wet pores and oil-wet pores, investigating the effect of CO2 phase (gas/liquid/supercritical). The CO2 phase significantly affects the CO2-fluid contact angle in an oil-wet pore. Supercritical CO2-fluid contact angles are larger than gas CO2-fluid contact angles, but are smaller than liquid CO2-fluid contact angles. However, this significant CO2 phase effect on contact angle was not observed in a water-wet pore. Another key issue considered in this study is two-phase flow displacement in porous media. This strongly relates to the important macroscopic parameters for multiphase flow transport in porous media, such as capillary pressure and relative permeability. Here CO2-water displacements are studied by conducting CO2 flooding experiments in a sandstone core sample, considering the effects of CO2 phase, pressure and CO2 injection rate. The capillary pressure-saturation curve, water production behaviour and relative permeability are investigated for gas CO2-water, liquid CO2-water and supercritical CO2-water displacements in porous media. The pressure-dependant drainage capillary pressures are obtained as a result of CO2-water interfacial tension. Various water production behaviours are obtained for gas CO2-water and liquid CO2-water displacements, mainly due to the effect of CO2 dissolution. The significant irregular capillary pressure-saturation curves and water production behaviors can be observed for the supercritical CO2-water displacements. The water and CO2 relative permeabilities for CO2-water displacements in a porous media are then predicted.

The accumulation of carbon dioxide gas (CO2) in the atmosphere is considered be the main cause of global warming effects. These emissions can be reduced substantially by capturing and storing the CO2. The CO2SINK project started in April 2004 in the northeast German Basin (NEGB) at the town of Ketzin near Berlin, Germany. Uppsala University is one of the main participants in the seismic part of the CO2SINK project. Full waveform sonic data were acquired in the Ktzi-201 injection well at the Ketzin CO2 storage site. The mode of logging was monopole logging. The target was the Stuttgart Formation, a saline sandstone aquifer at the depth of 500-700m. A total of 1210 shots were conducted and data were recorded on 13 channels. Receiver spacing was 6 inches (15.24 cm). The focus of the CO2SINK project was to develop the basis for the CCS technique by injecting CO2 into a saline aquifer and monitoring of the injected CO2 in the aquifer as a pilot study for future geological storage of CO2 in Europe. The objective of this study is to calculate P-wave & S-wave velocities from full waveform sonic data recorded in Ktzi-201 injection well. In hard formations, shear wave velocities can be determined directly from full waveform sonic data recorded in monopole logging. However, in slow formations like Stuttgart Formation as in the Ketzin CO2SINK project, shear wave arrivals are absent in full waveform sonic data recorded in monopole logging. In this case, shear wave velocities can be determined from Stoneley wave velocities provided that one knows the P-wave velocity in the borehole fluid. P-wave velocities were calculated by picking the P-wave arrivals on full waveform sonic data. Due to the absence of shear wave arrivals, the shear wave velocities were estimated from the larger amplitude Stoneley waves. The estimated S-wave velocities from Stoneley waves were less than the fluid wave velocity in the borehole, confirming the mode of logging was monopole and the formation is a slow formation. The reliability of shear wave velocities estimated from Stoneley waves also depends on five other parameters such as formation permeability, borehole fluid property, tool diameter, borehole radius etc.

This project studied the physical and chemical effects of typical impurities on CO2 storage using both experimental approaches and theoretical simulation. Results show that the presence of typical non-condensable impurities from oxyfuel combustion such as N2, O2, and Ar resulted in lower density than pure CO2, leading to decreased CO2 storage capacity and increased buoyancy in saline aquifers. In contrast, inclusion of condensable SO2 in CO2 resulted in higher density than pure CO2 and therefore increased storage capacity. These impurities also had a significant impact on the phase behaviours of CO2, which is important to CO2 transportation. Different effects on rock chemistry were detected with experimental systems containing pure CO2, CO2 with SO2, or CO2 with SO2 and O2 under conditions simulating that in a potential storage site. An equation was proposed to predict the effects of the rock chemistry on the porosity of rocks.

The transition to efficient, affordable, reliable, and clean sources of energy is one of the major challenges of this century. Despite advances in renewable energy technologies, fossil fuels remain the primary source of energy, and are expected to remain so for decades to come. Natural gas, a relatively cleaner fossil fuel vital to many industries such as power generation, is expected to play a more prominent role in the global energy mix. However, with the decline in conventional gas discoveries, it is crucial to improve recovery from mature reservoirs to satisfy the growing demand for energy. On the other hand, the combustion of fossil fuels significantly contributes to carbon dioxide (CO2) emissions and climate change, an issue of major concern. CO2-based enhanced gas recovery (EGR) is a useful method to improve gas recovery, and simultaneously store CO2 securely in depleted gas reservoirs, therefore reducing net CO2 emissions. However, CO2 injection for EGR has a drawback of excess mixing with the methane therefore reducing the quality of gas produced, and leading to early breakthrough. Although this issue has been identified as a major obstacle in CO2-based EGR, few strategies have been suggested to mitigate this problem. In this study, we propose a novel hybrid EGR method to reduce mixing and delay breakthrough. We propose the injection of a slug of carbonated water before beginning CO2 injection. Carbonated water hinders CO2-methane mixing, and reduces CO2 mobility therefore delaying breakthrough. We use reservoir simulation to assess the feasibility and benefit of the proposed method. Through a structured design of experiments (DoE) framework, we perform sensitivity analysis, uncertainty quantification, and optimization to identify the ideal operation and transition conditions. We show that the proposed method has an overall benefit for up to ~3% pore volumes of carbonated water injected. The proposed method is mainly influenced by the heterogeneity of the reservoir, slug volume injected, and production rates. Through Monte Carlo simulation we show that high recovery factors and storage ratios can be achieved while keeping recycled CO2 ratios low. These results are encouraging and highlight the overall benefit of the proposed hybrid EGR method.

Owing to the excess of carbon dioxide emissions in the atmosphere, a transition to a neutral carbon economy is needed. In this framework, Carbon Capture and Storage (CCS), and Carbon Capture Utilization and Storage (CCUS) become essential areas of development. Sequestering CO2 into different geological media such as deep saline aquifers and hydrocarbon reservoirs reduces the net anthropogenic gas emissions. In 2020, the global CO2 emissions corresponded to 31.5 gigatons. In the case of Saudi Arabia, the Riyadh province emitted 45.8 megatons. This study aims to evaluate for the first time the CO2 storage potential of the Unayzah Formation in Saudi Arabia, identify the primary trapping mechanisms, and capture the effects of the highly heterogeneous reservoir. CO2 injection in geological media is challenging because of the complexity of the geological properties and the CO2 phase behavior at super-critical conditions. In the present evaluation, we constructed a geological model only with public domain data. Similarly, we obtained different scenarios of the model on account of the uncertainty in the geological parameters. Later on, we selected a base model representing a conservative scenario to perform high-resolution simulations to determine the dominant mechanisms influencing the storage efficiency. In the main analysis, we simulated continuous injection of CO2 for forty years followed by twenty years of monitoring. We tested the injectivity of the reservoir showing it is possible to inject 1 and 2 megatons in vertical and horizontal wells, respectively. Likewise, lower injection rates improved solubility and residual trapping. Residual trapping is dominant, and it could reach fifty percent, while solubility could reach up to fifteen percent of the total CO2 injected. Along with these scenarios, we performed an Uncertainty Analysis based on porosity and permeability multipliers, salinity, and hysteresis effect. Finally, we demonstrated the effectiveness of the seal, and the structural and stratigraphic trapping. Until the development of the current analysis, there is no evidence of public domain studies assessing the storage potential into saline aquifers in Saudi Arabia. This contribution is essential for developing CCUS and promoting a circular carbon economy in line with the Vision of the Kingdom for the future.

One of the most promising mitigation strategies for greenhouse gas accumulation in the atmosphere is carbon capture and storage (CCS). Deep saline aquifers are seen as the most efficient carbon dioxide (CO2) storage sites, mainly because of their vast size and worldwide distribution. Injecting CO2 into brine filled media will cause a physical and chemical disequilibrium in the formation. This PhD thesis documents the investigation of some of the resulting effects which occur at the beginning of the injection, during the injection period and millions of years after injection. When CO2 is injected into a brine filled reservoir, large amounts of in situ brine will be displaced away from the injection well. This causes a pressure increase in the vicinity of the well which may compromise the injection process. The simulation of this pressure increase was performed with the black-oil simulator Eclipse10 (Schlumberger) while using a number of recent formulas to predict the mutual dissolution and the fluid properties of CO2 and brine. The results show that the pressure increase can exceed the maximum sustainable pore pressure and will cause fracturing of the reservoir formation. The pore pressure increase is dependent on parameters such as temperature and salinity because they change the fluid properties of the CO2 and brine, but also the capability of the fluids to dissolve mutually. The mutual dissolution has generally a pressure reducing effect although its impact is regarded to be overestimated. This is mainly because reservoir engineering software cannot simulate the shock front realistically. Undulations, which appear on the injection pressure profile are not a result of model instabilities but can either be related to enhanced mutual dissolution due to grid effects, or to the software which may overestimate or underestimate the pressure and dissolution. A detailed investigation of those undulations is vital for the interpretation of the injection pressure. High fluid pressure can be an important parameter for the estimation of the CO2 storage capacity of saline aquifers such as the offshore Bunter Sandstone Formation, in the UK southern North Sea. Based on fluid pressure, the 1 storage capacity was calculated using the ECLIPSE compositional simulation package and a simple analytical equation. The estimated storage capacity is 6.55 to 7.17 Gt of CO2 calculated with the analytical and the numerical approach respectively. By comparing the results, the differences are relatively moderate and therefore the application of the numerical simulator is not regarded as necessary. This is mainly due to the effective pressure flow which prevents pressure accumulations underneath the cap rock. Although the CO2 storage capacity of the Bunter Sandstone Formation remains high, a previous survey, which was not based on fluid pressure, calculated a storage capacity approximately twice as high as the results presented here. In theory, due to the increase in CO2 concentration, CO2 bearing carbonate minerals could precipitate when CO2 is injected into an aquifer such as the Rotliegend aquifer in the southern North Sea. Geochemical models often predict a relatively rapid growth of carbonate minerals as the most secure form of long term engineered CO2 storage. But validation of model-results remains difficult due to the long periods of time involved. Natural analogue studies can bridge the gap between experiments and real-world storage. The Fizzy field, a southern North Sea (UK) gas accumulation with a high natural CO2 content (c. 50%) provides an ideal opportunity to study the long term effect of CO2 related mineral reaction. However all such reservoirs contain ‘normal’ diagenetic dolomite, so that distinguishing sequestration related dolomite is a challenge. CO2 was stepwise extracted from dolomite from both the Fizzy field and the Orwell Rotliegend sandstone in order to reveal any zonation of the crystals which could be related to enhanced dolomite precipitation due to the high CO2 concentration. According to the method between 0 and 22 % of the dolomite in the Fizzy field precipitated due to the high CO2 concentration. Therefore, between 0 and 19 % of the CO2, which is related to the relatively recent high CO2 concentration, is ‘trapped’ in the ‘sequestration dolomite’. The wide range of this estimate is mainly related to rock heterogeneity.

L'objectif de cette thèse était de modéliser à partir des expériences de percolation-réactive, les processus hydrodynamique et réactionnel qui gouvernent l'altération des ciments de puits. Différentes expériences ont été réalisées dans des conditions représentatives de celles du stockage du CO2. Des échantillons fracturés ont été utilisés pour injecter une saumure enrichie en CO2 à 60°C et 10MPa et à différentes pressions partielles de CO2. Le débit d'injection variait en fonction des propriétés hydrauliques de l'échantillon exposé. L'injection d'une saumure enrichie en CO2 à débit constant à travers une fracture supposée plane a permis d'étudier les modifications des propriétés hydrodynamiques et ces conséquences sur la géochimie et la microstructure du ciment altérée. L'impact dynamique de l'évolution microstructurale a été mis en évidence. Les expériences conduites sur des échantillons présentant de larges ouvertures, réalisées sur une durée de 5 h, ont montré que la perméabilité était maintenue constante le long de l'expérience. Trois couches d'altération se sont développées consécutivement à la dissolution de la portlandite et la décalcification des CSH. L'altération a entrainé la précipitation des carbonates et de la silice amorphe à proximité de la fracture. Dans le cas d'une expérience longue durée appliquant les mêmes conditions que précédemment on a observé que la croissance de la silice amorphe a entrainé la diminution de la perméabilité. Par ailleurs les expériences effectuées sur des échantillons présentant de faibles ouvertures, ont indiqué que la conversion de la portlandite en calcite conduit au colmatage de la fracture. L'évolution des assemblages de phases conduisant à la formation des carbonates et de la silice amorphe ont été modélisés à partir du code géochimique GEMS. Les mécanismes de diffusion et les processus de mise en place des couches d'altération ont été étudiés à partir d'un modèle analytique et d'un modèle de transport réactif à partir du code géochimique PHREEQC. Mots-clés Percolation-réactive, processus hydrodynamique et thermochimique, altération, ciments de puits, stockage du CO2, modélisation. / Title: “Experimental characterization and modelling of the alteration of fractured cement under CO2 storage conditions.”The main purpose of this thesis was to characterize and to model the hydrodynamic and thermochemical processes leading to the alteration of the wellbore cement materials under borehole conditions. Percolation experiments were performed on fractured cement samples under CO2 storage conditions (60°C and 10MPa). Injection flow rate was dictated by the fracture aperture of each sample. CO2 enriched brine was flowed along the fracture aperture, and permeability changes as well as chemical evolution of major cations were continuously acquired during the experiment time. Reaction paths developed by the alteration of the cement were characterized using microtomography and ESEM images. The experiments conducted using samples presenting large fracture apertures during 5h showed that permeability was maintained constant during the experiment time. Three reacted layers were displaying by the alteration of portlandite and CSH. Long term experiment conducted with large initial fracture aperture showed a decrease of the permeability after 15hours of CO2 exposure. Otherwise, experiments performed on samples presenting narrow apertures indicated the conversion of portlandite and CSH to calcite leading to the permeability reduction and the fracture clogging. Assemblages of phases and chemical changes were modelled using GEMS-PSI speciation code. We studied also using a coupled transport-reactive model the conditions leading to the cement alteration and the formation of associated layers.Key words: Hydrodynamic and thermochemical processes, alteration, wellbore cement, CO2 storage, percolation experiments, numerical modeling.

Capturing and storing carbon dioxide (CO2) underground for thousands of years is one way to reduce atmospheric greenhouse gases, often associated with global warming. Leakage of CO2 through wells is one of the major concerns when storing CO2 in depleted oil and gas reservoirs. CO2-injection candidates could be new wells, or old wells that are active, closed or abandoned. To prevent the leakage, the possible leakage paths and the mechanisms triggering these paths must be examined and identified. It is known that the leakage paths can occur due to CO2-rock interaction and CO2-water-cement interaction. Interaction between well cement and carbon dioxide has attracted much renewed interest because of its implication in geological storage of carbon dioxide. The diffusion of CO2-water through well cement is a long-term phenomenon which can take many thousand years. Partial pressure, porosity, permeability, cement type, moisture content and temperature are the factors that affect the carbonation of well cement. The objective of this research is to investigate the chemical reactions of the dissolved CO2 in the synthetic formation water with the plugs of well cement. Cement specimens were left in contact with CO2 saturated brine at 1100 psi and 65

Numerical simulation has been used, as common practice, to estimate the CO2 storage capacity of depleted reservoirs. However, this method is time consuming, expensive and requires detailed input data. This investigation proposes an analytical method to estimate the ultimate CO2 storage in depleted oil and gas reservoirs by implementing a volume constrained thermodynamic equation of state (EOS) using the reservoir?s average pressure and fluid composition. This method was implemented in an algorithm which allows fast and accurate estimations of final storage, which can be used to select target storage reservoirs, and design the injection scheme and surface facilities. Impurities such as nitrogen and carbon monoxide, usually contained in power plant flue gases, are considered in the injection stream and can be handled correctly in the proposed algorithm by using their thermodynamic properties into the EOS. Results from analytical method presented excellent agreement with those from reservoir simulation. Ultimate CO2 storage capacity was predicted with an average difference of 1.3%, molar basis, between analytical and numerical methods; average oil, gas, and water saturations were also matched. Additionally, the analytical algorithm performed several orders of magnitude faster than numerical simulation, with an average of 5 seconds per run.