• Energy Research

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 %).

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.

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

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.