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AbstractThe migration of CO2 stored in deep saline aquifers depends on the morphology of the top of the aquifer. Topographical highs, such as anticlines, may trap CO2 and limit the distance migrated, or elevated ridges may provide pathways enabling CO2 to migrate further from the injector. For example, seismic data of the Utsira formation at the Sleipner storage site indicates that a branch of the CO2 plume is moving to the north [1]. It is therefore important to study the interface between the aquifer and the caprock when assessing risk as CO2 storage sites.Undulations in the top surface of an aquifer may either be caused by sedimentary structures [2], or by folding. In addition, irregularities may be generated by faulting [2]. Large-scale features are detected using seismic data (i.e. structures with amplitudes greater than 10 m), and such structures will generally be included in reservoir or aquifer models. However, smaller- scale features could also have an effect on a CO2 plume migration, and this is the topic of our study. We have conducted simulations in models with a range of top-surface morphology, and have examined the distance migrated and the amount of dissolution.The results from this study suggest that the effects of sub-seismic variations in the topography of the aquifer/caprock interface are unlikely to have a significant impact on the migration and dissolution of CO2 in a saline aquifer, compared with tilt or permeability anisotropy. The results were most sensitive to the kv/kh ratio during the injection period.

Deep saline aquifers used for CO$_2$ sequestration are commonly made of sedimentary formations consisting of several layers of distinguishable permeability. In this work, the effect of a non-monotonic, vertically varying permeability profile on the onset of convective instability is studied theoretically using linear stability analyses. The onset time depends on the interaction between the permeability profile and the location of the concentration perturbation peak beyond which the concentration of CO$_2$ decays. A thin low-permeability layer can either accelerate or delay the onset time of the convective instability depending on the nature of the permeability variation - whether the permeability transition is smooth or layered, the Rayleigh number (Ra), and the location of the permeability change ($\hat{a}$) relative to the perturbation peak ($\hat{a}_{c^{*}}$), which scales as $\hat{a}_{c^{*}}\approx 14Ra^{-1}$ for homogeneous systems. However, the low permeable layer has no effect on the onset time when it is near the lower boundary of a medium with sufficiently large Ra ($\hat{a}_{c^{*}} \ll \hat{a}$). This nontrivial dependence highlights the implication of ignoring geological features of a small spatial extent, indicating the importance of a detailed characterization of CO$_2$ storage sites. 27 pages, 9 figures

Abstract The wettability of a formation is defined as the tendency of one fluid to spread on a surface in competition with other fluids which are also in contact with it. However, the impact of temperature on wettability in an aquifer and the modification of relative permeability curves based on the temperature variation in aquifers is not well covered in the literature. This study redresses this dearth of information by investigating the impact of temperature on wettability distribution in a reservoir and updating the relative permeability curves based on its temperature propagation. The impact of the latter is studied in relation to the solubility of CO2 injected into an aquifer using the numerical methods (i.e. ECLIPSE). If the CO2 injected has a temperature higher than the formation geothermal temperature, it can change the wettability of the formation further to a more CO2 wet condition. This increases the risk of leakage and also changes the relative permeability curves as the CO2 moves through the reservoir, a situation that needs to be considered in reservoir simulations. The results show that updating and modifying the relative permeability curves with temperature variation in an aquifer can increase the amount of CO2 dissolution there.

CO2 injection into geological formations is considered one way of mitigating the increasing levels of carbon dioxide concentrations in the atmosphere and its effect on and global warming. In regard to sequestering carbon underground, different countries have conducted projects at commercial scale or pilot scale and some have plans to develop potential storage geological formations for carbon dioxide storage. In this study, pure CO2 injection is examined on a model with the properties of bunter sandstone and then sensitivity analyses were conducted for some of the fluid, rock and injection parameters. The results of this study show that the extent to which CO2 has been convected in the porous media in the reservoir plays a vital role in improving the CO2 dissolution in brine and safety of its long term storage. We conclude that heterogeneous permeability plays a crucial role on the saturation distribution and can increase or decrease the amount of dissolved CO2 in water around ± 7% after the injection stops and up to 13% after 120 years. Furthermore, the value of absolute permeability controls the effect of the Kv/Kh ratio on the CO2 dissolution in brine. In other words, as the value of vertical and horizontal permeability decreases (i.e., tight reservoirs) the impact of Kv/Kh ratio on the dissolved CO2 in brine becomes more prominent. Additionally, reservoir engineering parameters, such as well location, injection rate and scenarios, also have a high impact on the amount of dissolved CO2 and can change the dissolution up to 26%, 100% and 5.5%, respectively.

Les puits forés dans des sites de stockage de carbone pourraient être convertis en voies de fuite potentielles en présence de fluides contenant du CO2 et sous l'impact des changements survenant dans le stress souterrain. Pour tester cette hypothèse, dans cette étude, le comportement du ciment de puits de pétrole de classe G en contact avec le CO2 supercritique a été étudié. Les noyaux de ciment ont été durcis sous eau saturée de chaux pendant 28 jours à une température de 20 °C et sous pression atmosphérique. Par la suite, ils ont été exposés à du CO2 supercritique sous une pression de 20 MPa et à une température de 90 °C pendant 30 jours. La profondeur de pénétration du front de carbonatation et le changement des propriétés poromécaniques du noyau de ciment ont été mesurés en fonction du temps. Un exercice de modélisation numérique a également été mené pour simuler l'altération dans les carottes de ciment. Les résultats présentés dans cette étude montrent que la précipitation des carbonates de calcium réduit la porosité au sein des couches les plus externes des noyaux de ciment. Ce phénomène déplace la classe de taille de pore principale vers des tailles plus petites. Contrairement aux attentes, la réduction de la porosité n'améliore pas la résistance globale des échantillons de ciment. La réduction observée de la résistance des échantillons de ciment pourrait être associée soit à la structure amorphe des carbonates précipités, soit à la faible liaison entre eux et les parois solides des pores et à la forte dégradation des hydrates de silicate de calcium. Los pozos perforados en los sitios de almacenamiento de carbono podrían convertirse en posibles vías de fuga en presencia de fluidos que contengan CO2 y bajo el impacto de los cambios que ocurren en la tensión subterránea. Para probar esta hipótesis, en este estudio, se ha investigado el comportamiento del cemento de pozo petrolífero Clase G en contacto con CO2 supercrítico. Los núcleos de cemento se curaron bajo agua saturada de cal durante 28 días a una temperatura de 20 °C y a presión atmosférica. Posteriormente, se expusieron a CO2 supercrítico a una presión de 20 MPa y a una temperatura de 90 ºC durante 30 días. La profundidad de penetración del frente de carbonatación y el cambio en las propiedades poromecánicas del núcleo de cemento se midieron frente al tiempo. También se ha realizado un ejercicio de modelado numérico para simular la alteración dentro de los núcleos de cemento. Los resultados presentados en este estudio muestran que la precipitación de carbonatos de calcio reduce la porosidad dentro de las capas más externas de los núcleos de cemento. Este fenómeno desplaza la clase de tamaño de poro principal hacia tamaños más pequeños. En contraste con las expectativas, la reducción de la porosidad no mejora la resistencia general de las muestras de cemento. La reducción observada en la resistencia de las muestras de cemento podría estar asociada con la estructura amorfa de los carbonatos precipitados o la débil unión entre ellos y las paredes sólidas de los poros y la alta degradación de los hidratos de silicato de calcio. Wells drilled in carbon storage sites could be converted to potential leakage pathways in the presence of CO2-bearing fluids and under the impact of the changes occurring in underground stress. To test this hypothesis, in this study, the behavior of Class G oil well cement in contact with supercritical CO2 has been investigated. The cement cores were cured under lime-saturated water for 28 days at a temperature of 20 ∘C and under atmospheric pressure. Subsequently, they were exposed to supercritical CO2 under a pressure of 20 MPa and at a temperature of 90 ∘C for 30 days. The penetration depth of the carbonation front and the change in the poromechanical properties of the cement core were measured against time. A numerical modeling exercise has also been conducted to simulate the alteration within the cement cores. The results presented in this study show that the precipitation of calcium carbonates reduces the porosity within the outermost layers of the cement cores. This phenomenon shifts the main pore size class towards smaller sizes. In contrast to expectations, the reduction in porosity does not improve the overall strength of the cement specimens. The observed reduction in the strength of the cement specimens might be associated with either the amorphous structure of the precipitated carbonates or the weak bonding between them and the solid walls of the pores and the high degradation of calcium silicate hydrates. يمكن تحويل الآبار المحفورة في مواقع تخزين الكربون إلى مسارات تسرب محتملة في وجود سوائل حاملة لثاني أكسيد الكربون وتحت تأثير التغيرات التي تحدث في الإجهاد تحت الأرض. لاختبار هذه الفرضية، في هذه الدراسة، تم التحقيق في سلوك أسمنت بئر النفط من الفئة ز في اتصال مع ثاني أكسيد الكربون فوق الحرج. تمت معالجة قلوب الأسمنت تحت الماء المشبع بالجير لمدة 28 يومًا عند درجة حرارة 20 درجةمئوية وتحت الضغط الجوي. بعد ذلك، تعرضوا لثاني أكسيد الكربون فوق الحرج تحت ضغط 20 ميجا باسكال وعند درجة حرارة 90 درجةمئوية لمدة 30 يومًا. تم قياس عمق اختراق جبهة الكربنة والتغير في الخصائص الميكانيكية البورومية لقلب الأسمنت مع مرور الوقت. كما تم إجراء تمرين نمذجة رقمية لمحاكاة التغيير داخل النوى الأسمنتية. تظهر النتائج المقدمة في هذه الدراسة أن ترسيب كربونات الكالسيوم يقلل من المسامية داخل الطبقات الخارجية من النوى الأسمنتية. تحول هذه الظاهرة فئة حجم المسام الرئيسية نحو أحجام أصغر. وعلى النقيض من التوقعات، فإن انخفاض المسامية لا يحسن القوة الإجمالية لعينات الأسمنت. قد يرتبط الانخفاض الملحوظ في قوة عينات الأسمنت إما بالبنية غير المتبلورة للكربونات المترسبة أو الترابط الضعيف بينها وبين الجدران الصلبة للمسام والتحلل العالي لهيدرات سيليكات الكالسيوم.

The UK plans to bring all greenhouse gas emissions to net-zero by 2050. Carbon capture and storage (CCS), an important strategy to reduce global CO2 emissions, is one of the critical objectives of this UK net-zero plan. Among the possible storage site options, saline aquifers are one of the most promising candidates for long-term CO2 sequestrations. Despite its promising potential, few studies have been conducted on the CO2 storage process in the Bunter Closure 36 model located off the eastern shore of the UK. Located amid a number of oil fields, Bunter is one of the primary candidates for CO2 storage in the UK, with plans to store more than 280 Mt of CO2 from injections starting in 2027. As saline aquifers are usually sparsely drilled with minimal dynamic data, any model is subject to a level of uncertainty. This is the first study on the impact of the model and fluid uncertainties on the CO2 storage process in Bunter. This study attempted to fully accommodate the uncertainty space on Bunter by performing twenty thousand forward simulations using a vertical equilibrium-based simulator. The joint impact of five uncertain parameters using data-driven models was analysed. The results of this work will improve our understanding of the carbon storage process in the Bunter model before the injection phase is initiated. Due to the complexity of the model, it is not recommended to make a general statement about the influence of a single variable on CO2 plume migration in the Bunter model. The reservoir temperature was shown to have the most impact on the plume dynamics (overall importance of 41%), followed by pressure (21%), permeability (17%), elevation (13%), and porosity (8%), respectively. The results also showed that a lower temperature and higher pressure in the Bunter reservoir condition would result in a higher density and, consequently, a higher structural capacity.

Abstract Numerical models of geologic carbon sequestration (GCS) in saline aquifers use multiphase fluid flow-characteristic curves (relative permeability and capillary pressure) to represent the interactions of the non-wetting CO2 and the wetting brine. Relative permeability data for many sedimentary formations is very scarce, resulting in the utilisation of mathematical correlations to generate the fluid flow characteristics in these formations. The flow models are essential for the prediction of CO2 storage capacity and trapping mechanisms in the geological media. The observation of pressure dissipation across the storage and sealing formations is relevant for storage capacity and geomechanical analysis during CO2 injection. This paper evaluates the relevance of representing relative permeability variations in the sealing formation when modelling geological CO2 sequestration processes. Here we concentrate on gradational changes in the lower part of the caprock, particularly how they affect pressure evolution within the entire sealing formation when duly represented by relative permeability functions. The results demonstrate the importance of accounting for pore size variations in the mathematical model adopted to generate the characteristic curves for GCS analysis. Gradational changes at the base of the caprock influence the magnitude of pressure that propagates vertically into the caprock from the aquifer, especially at the critical zone (i.e. the region overlying the CO2 plume accumulating at the reservoir-seal interface). A higher degree of overpressure and CO2 storage capacity was observed at the base of caprocks that showed gradation. These results illustrate the need to obtain reliable relative permeability functions for GCS, beyond just permeability and porosity data. The study provides a formative principle for geomechanical simulations that study the possibility of pressure-induced caprock failure during CO2 sequestration.

The implementation of CO2 storage in sub-surface sedimentary formations can involve decision making using relevant numerical modelling. These models are often represented by 2D or 3D grids that show an abrupt boundary between the reservoir and the seal lithologies. However, in an actual geological formation, an abrupt contact does not always exist at the interface between distinct clastic lithologies such as sandstone and shale. This article presents a numerical investigation of the effect of sediment-size variation on CO2 transport processes in saline aquifers. Using the Triassic Bunter Sandstone Formation (BSF) of the Southern North Sea (SNS), this study investigates the impact a gradation change at the reservoir-seal interface on CO2 sequestration. This is of great interest due to the importance of enhanced geological detail in reservoir models used to predict CO2 plume migration and the integrity of trapping mechanisms within the storage formation. The simplified strategy was to apply the Van Genutchen formulation to establish constitutive relationships for pore geometric properties, which include capillary pressure (Pc) and relative permeability (kr), as a function of brine saturation in the porous media. The results show that the existence of sediment gradation at the reservoir-seal interface and within the reservoir has an important effect on CO2 migration and pressure diffusion in the formation. The modelling exercise shows that these features can lead to an increase in residual gas trapping in the reservoir and localised pore pressures at the caprock’s injection point.