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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.

Abstract Several researchers have studied the Sleipner model to understand the inherent flow physics better, to find a satisfactory match of the CO2 plume migration. Various sources of uncertainty in the geological model and the fluid have been investigated. Most of the work undertaken on the Sleipner model employed the one factor at a time (OFAT) method and analysed the impact of uncertain parameters on plume match individually. In this study, we have investigated the impact of some of the most cited sources of uncertainties including porosity, permeability, caprock elevation, reservoir temperature, reservoir pressure and injection rate on CO2 plume migration and structural tapping in the Sleipner. We tried to fully span the uncertainty space on Sleipner 2019 Benchmark (Layer 9) using a vertical-equilibrium based simulator. To the best of our knowledge, this is the first time that a study has focused on the joint effect of six uncertain parameters using data-driven models. This work would raise our scientific understanding of the complexity of the impact of the reservoir uncertainty on CO2 plume migration in a real field model. The caprock elevation was shown to be the most important parameter in controlling the plume migration (overall importance of 26 %) followed by injection rate (24 %), temperature (22 %), heterogeneity in permeability (13 %), pressure (9 %) and porosity (6 %).

AbstractPredicting CO2 plume migration is an important aspect for the geological sequestration of CO2. In the absence of experimental data, the storage performance of CO2 geo‐storage can be assessed through the dynamic modelling of the fluid flow and transport properties of the rock‐fluid system using empirical formulations. Using the van Genuchten empirical model, this study documents a Darcy flow modelling approach to investigate different aspects of CO2 drainage in a sandstone formation with interbedded argillaceous (i.e. mudstone) units. The numerical simulation is based on the Sleipner gas field storage unit where several thin argillite layers occur within the sandstone of the Utsira Formation. With respect to forward modelling simulations that have used Sleipner Formation as a case study, it is noted that previous attempts to numerically calibrate the CO2 plume migration to time‐lapse seismic dataset using software governed by Darcy flow physics achieved poor results. In this study, CO2‐brine buoyant displacement pattern is simulated using the ECLIPSE ‘black oil’ simulator within a two‐dimensional axisymmetric geometry and a three‐dimensional Cartesian coordinate system. This investigation focussed on two key parameters affecting CO2 migration mobility, namely relative permeability and capillary forces. Examination of these parameters indicate that for the gravity current of CO2 transiting through a heterogeneous siliciclastic formation, the local capillary forces in geologic units, such as mudstone and sandstones, and the relative permeability to the invading fluid control the mass of CO2 that breaches and percolates through each unit, respectively. In numerical analysis, these processes influence the evaluation of structural and residual trapping mechanisms. Consequently, the inclusion of heterogeneities in capillary pressure and relative permeability functions, where and when applicable, advances a Darcy modelling approach to history matching and forecasting of reservoir performance. Results indicate that there is a scope for a revision of the basic premise for modelling flow properties in the interbedded mudstones and the top sand wedge at the Sleipner Field when using Darcy flow simulators. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

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.

Abstract Different injection methods have been already proposed by different researchers to improve the solubility of CO2 in formation brine. In this study a novel injection technique is presented, its aim being to cool down (liquefy) the supercritical CO2 injected in a wellbore through the use of downhole cooler equipment. Higher temperature CO2 entering the cooling equipment therefore exits with a lower temperature further downstream. If the temperature of the downhole, where CO2 is in contact with the formation brine, decreases to the lowest possible safe operational temperature, the consequence is an increase in the solubility of CO2 to the highest possible value for that pressure. The colder (liquid) CO2 has a higher solubility in brine, higher density and viscosity, which increases the security of the CO2 storage. Using this method to cool the supercritical CO2 down to a liquid phase increases its solubility at the wellbore, thereby eliminating the risk of a phase change or pressure and rate fluctuation in the liquid CO2 injection from the surface. Additionally the formation will have a lower pressure build-up because CO2 and brine are well mixed, and so less CO2 remains in the free phase.

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.

Abstract In the application of two-phase flow in porous media within the context of CO2 sequestration, a non-wetting phase is used to displace a wetting phase residing in-situ to the maximum extent through a network of pore conduits. The storage performance of this physical process can be assessed through numerical simulations where transport properties are usually described using the Brooks & Corey (BC) or van Genuchten (vG) model. The empirical constant, namely the pore geometry index, is a primary parameter in both of these models and experimental evidence shows a variation in the value of this empirical constant. It is, therefore, essential to cast this empirical constant into a ternary diagram for all types of clastic porous media to demarcate the efficiency of two-phase flow processes in terms of the pore geometry index (PGI). In doing so, this approach can be used as a tool for designing more efficient processes, as well as for the normative characterisation of two-phase flow, taking into consideration the predominance of capillary pressure or relative permeability effects. This concept is based on the existence of a PGI estimation for clastic sediments, for which the value for 12 sediment mixtures fall between 1.01 and 3.00. Statistical data obtained from soil physics is used for developing and validating numerical models where a good match is observed in numerical simulations. In this context, a new methodology for the effective characterisation of PGI for different clastic rocks is proposed. This paper presents theoretical observations and continuum-scale numerical simulation results of a PGI characterisation for the prediction of the hydraulic properties of clastic reservoir rocks. The effect of key parameters in the vG empirical model, such as the pressure strength coefficient and the PGI, is incorporated into the simulation analysis. In particular, the model is used to investigate the effects of parameter representation on CO2 storage performance in a saline aquifer. Subsequent analysis shows that the PGI is a very important parameter for defining the flow characteristics of simulation models. It can also be flexibly changed for each rock type and this approach may thus be practical when simulating the evolution of CO2 plume in reservoirs with sedimentary heterogeneities, such as intra-aquifer aquitard layers or graded beds. The use of the realistic PGI boundaries promises a more precise description of the hydraulic behaviour in sandstones and shale when using either the BC or vG model.

Abstract The injection of carbon dioxide (CO2) captured from combustion-based processes into underground formations is one of a number of plausible methods to reduce its release into the atmosphere and consequential greenhouse gas warming. Once the gas has been captured efficiently and effectively, depleted oil and gas reservoirs are seen as high potential candidates for carbon storage projects. However, legacy issues associated with a high number of oil and gas wells abandoned during the last few decades put the carbon capture and storage projects (CCS) at risk. These include any defects within the cement surrounding the well casing or for capping an abandoned well that can become unwanted CO2 leakage pathways. To predict the lifespan of these cements due to exposure to CO2-bearing fluids at the conditions found underground, the geochemical processes need to be coupled with the geomechanical changes within the cement matrix. In a viable CCS project for sequestering CO2, the cement matrix should be capable of withstanding acidic environments formed by dissolution of CO2 in brine for more than ten thousand years. This work aims at providing a framework to predict the behaviour of cement due to CO2 exposure under reservoir conditions. The results show that the chemical reactions and geomechanical changes within the cement matrix can result either in its radial cracking or radial compaction. Both of these behaviours are investigated as possible phenomena which may affect the CO2 leakage, and therefore the viability of the site for long term carbon storage.

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.