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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 %).

Abstract Exhumed bleached palaeoreservoirs provide a means of understanding fluid flow processes in geological media because the former movement of fluids is preserved as visible geochemical changes (grey bleaching of continental red-beds). The bleached palaeoreservoirs of the Jurassic Entrada Sandstone occur in a region (Utah) where there are high fluxes of naturally-occurring CO2 and form outcrop analogues for processes related to geological storage of CO2. In this paper a bleached palaeoreservoir now exposed at outcrop is used to test the importance of geological heterogeneity on fluid flow. The bleached palaeoreservoir is developed in ‘wet aeolian’ lithofacies composed of alternating layers of sandstone and cemented muddy sandstone that range across three or more orders of magnitude in permeability. Despite these permeability contrasts the bleaching shows a remarkably uniform distribution within the palaeoreservoir that crosses lithofacies boundaries. Evidence from bleaching therefore suggests that geological heterogeneity within the range 1–103 millidarcies should not greatly impede the relatively uniform distribution of low-viscosity CO2 charged fluids throughout a reservoir: a conclusion that has been substantiated here by flow modelling. Residence time is an important factor and where flows are transient the distribution of bleaching and modelling shows that flows are confined to high-permeability lithofacies.

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 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.

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.

Abstract Small-scale deformation bands in Penrith Sandstone are used to assess the extent to which these features can act as effective mini-traps and contribute to secure CO2 geological storage. A comprehensive set of simulation scenarios is applied to one conjugate set of deformation bands and also to clusters of deformation bands, to evaluate the effects of i) deformation band density; ii) the contrast in host rock/deformation band permeability; and iii) deformation band geometry, orientation and distribution on fluid movement and its significance for CO2 storage capacity and security. The findings of this study show that one conjugate set of deformation bands can improve CO2 storage security, depending upon the plunge angle of the hinge. It has also been demonstrated that a high contrast in permeability (at least three orders of magnitude) is necessary for the CO2 to be effectively trapped by the deformation bands. It is shown that the highest number of bands observed and modelled for Penrith Sandstone outcrop, with three orders of magnitude permeability contrast, is a configuration that can contribute to the secure storage of CO2 without causing an injectivity issue. This study shows that storage security is not only controlled by the contrast in permeability, but also by the permeability of the host rock. Furthermore, some geometries may contribute to storage security, while others may compromise it. To improve storage capacity and security for the type of reservoir studied herein, the results demonstrate the importance of accounting for the optimum injection rate and well placement.

Abstract Saline aquifers constitute the most abundant geological storage option for Carbon Capture and Storage (CCS) projects. When injected in the aquifer, due to its lower density in comparison to the in-situ brine, the free phase CO2 tends to migrate upwards. This vertical migration is generally tens of metres depending on the reservoir thickness, despite the plume migration distance in the horizontal direction which could be over hundreds of kilometres (depending on the time horizon, reservoir characteristics, trapping mechanisms involved, etc.). In many situations, the plume ends up as a separate region below a sealing barrier. This large aspect ratio between the plume migration in the horizontal and vertical directions would potentially validate the use of vertical equilibrium (VE) models in CO2 storage studies. In other words, when phase segregation occurs rapidly compared to the time scale studied, vertical equilibrium can be assumed, allowing for the use of specially adapted models. In the VE model, the equilibrium between brine and CO2 is pre-assumed at all times. Under this assumption, the injected CO2 plume flow in 3D can be approximated in terms of its thickness in order to obtain a 2D simulation model, which consequently decreases the computational costs. The time by which phase segregation occurs depends on the aquifer thickness, aquifer permeability, fluid properties, etc. However, the CO2 and in-situ brine are separated considerably fast and form two separate layers, in comparison to the time period for lateral migration. The CO2lab module of the Matlab Reservoir Simulation Toolbox (MRST) used in this work, is a set of open source simulation and workflow tools to study the long-term, large-scale storage of CO2. We employed the VE tool in MRST−CO2lab (MVE) to study the effect of caprock morphology on the CO2 migration. The results have been compared with a number of simulators including ECLIPSE-black-oil (E100), ECLIPSE-compositional (E300) and ECLIPSE-VE (EVE) models and the differences between the approaches are analysed and discussed in detail. In particular, we focused on the impact of caprock morphology and aquifer top-surface slope on the CO2 structural and dissolution trapping mechanisms and plume migration. The results indicated a good agreement for the ultimate plume shapes in all the models. However, the amount of dissolved CO2 in the brine was different.

Abstract In this proposed CO 2 injection system, brine is extracted from the target storage aquifer by means of a lateral horizontal completion located near the top of the formation. It should be noted that the brine is not lifted to the surface. An Electrical Submersible Pump (ESP) is used to extract the brine and boost its pressure, before it is mixed with CO 2 that is injected down the vertical section of the well. The mixing takes place in the vertical section of the well below the upper lateral. The CO 2 –brine mix is then injected into the same formation through a lower lateral. A down-hole tool would be used to maximise agitation and contact area between CO 2 and brine in the vertical mixing section of the well, which may be tens to hundreds of metres long, depending on the thickness of the formation. The advantages of this method are that there is little overall pressure increase, because CO 2 is mixed with brine extracted from the formation, and also the extracted brine is already at high pressure when it is mixed with the CO 2 , greatly increasing the solubility of CO 2 and reducing the volume of brine required. Energy is not expended lifting the brine to surface nor is there any concern about handling large volumes of acidic brine in the surface equipment. In this study, in addition to the concept of the down-hole mixing (DHM) method which is presented, the application of the DHM method in a hypothetical storage site (Lincolnshire—Smith et al., 2012) is also examined. The calculations are performed to identify the optimum rates of water extraction and injection of dissolved CO 2 in brine.