CO2 Storage In Geological Formations Research Articles

A general review of CO2 sequestration in underground geological formations and assessment of depleted hydrocarbon reservoirs in the Niger Delta

This paper investigates the viability of CO2 storage in geological formations, including depleted hydrocarbon reservoirs applying 3-dimensional seismic and well data of the Niger Delta region as a case study for CO2 sequestration, which represents an essential initiative for the reduction of greenhouse gas emissions. Different theoretical and experimental studies from literature on CO2 sequestration in geological formations across the world, including the Niger Delta, are reviewed. The Niger Delta basin has a high potential for CO2 sequestration, and this indication is shown through the review of research papers undertaken outside and within the basin, which reveal the presence of massive hydrocarbon fields, lateral continuity of reservoir, reservoir-seal pairs, faults, and traps, developed hydrocarbon fields, appropriate reservoir depth. The gaps identified from the review of various research studies are analyzed to form the basis of a future research investigation for capturing, removing, and storing CO2 in depleted hydrocarbon reservoirs and other geological formations. The authors deduced that accurate injection pressure, rate, and depth estimation are critical factors for CO2 sequestration and need to be thoroughly investigated.

Investigation of supercritical CO2 mass transfer in porous media using X-ray micro-computed tomography

Understanding the mass transfer of CO2 into formation brine both qualitatively and quantitatively is important for improving the security of geologic carbon sequestration. In this study, quasi-dynamic X-ray micro-computed tomographic (MCT) imaging was used to track the time-evolution of supercritical CO2 (scCO2) clusters in a sandstone throughout brine injection. A cluster-matching workflow enabled the identification of depletion, merging, and snap-off of the scCO2 clusters, and subsequently the mass transfer coefficient of individual scCO2 clusters was found to range between 3.0×10−5 and 3.5×10−4 mm/s. The macroscopic average mass transfer coefficient was estimated as 1.4×10−4 mm/s. For application to geologic carbon sequestration, these values give an indication of the range of mass transfer coefficients that may be expected for similar state and flow conditions. With the macroscopic average mass transfer coefficient evaluated, we back-calculated the in-situ CO2 concentration field for brine, which provides quantitative insight of the distribution of dissolved CO2 in the sample. Despite slow injection rate (Ca = 10−7), mobilization of small scCO2 clusters was also observed, and was attributed to the combined effect of incomplete dissolution of snapped-off clusters and the reduction in the fluid–fluid interfacial tension (IFT) due to the high local CO2 concentration in brine accompanying scCO2 dissolution. This highlights the coupling of dissolution and mobilization processes and demonstrates the need to understand these interlinked dynamics to improve CO2 storage in geological formations.

Geologic CO2 Storage Optimization under Geomechanical Risk Using Coupled-Physics Models

Numerical simulation of fluid flow, transport, and trapping mechanisms have been used to optimize CO2 storage in geologic formations by improving trapping efficiency through injection strategies. Flow models, however, do not capture the geomechanical deformation that can occur during CO2 injection, including reservoir expansion, ground surface uplift, and induced seismicity. The geomechanical risks of CO2 injection have drawn more attention in recent years and coupled flow and geomechanical simulation models are increasingly used to study the geomechanical effects during CO2 injection, to ensure environmentally sound and safe operations. We present an optimization framework for geologic CO2 storage under geomechanical risks, where coupled flow-geomechanics simulations are used to quantify the risks of injection-induced ground surface deformation and rock failure in reservoir and caprock layers. A multi-objective optimization problem is formulated and solved to maximize CO2 storage while minimizing the two forms of geomechanical risks. The optimization decision variables include the locations of injection wells. Multiple numerical experiments with increasing complexity are presented to demonstrate the performance of the proposed framework. The results reveal optimal decisions that are different from those obtained from flow-only simulation that disregard the geomechanical risks associated with CO2 injection. When geomechanical risks are considered, the wells may not necessarily be concentrated in areas with the highest storage capacity because that may lead to rock failure and/or unacceptable levels of ground surface uplift. Overall, the observations from this study reveal important differences in optimization results and conclusions when geomechanical risks of geologic CO2 storage are considered.

RAND-based geochemical equilibrium algorithms with applications to underground geological storage of CO[formula omitted

Chemical and phase equilibrum (CPE) calculations are indispensable to the geochemical simulation of natural systems, such as freshwater, groundwater, and mineral formations. In natural environments, many chemical reactions occur, both at the interface between rocks and fluids (e.g., dissolution reactions) and in bulk phases (e.g., aqueous speciation). Moreover, the typical ionic species found in nature require thermodynamic models for electrolytes, increasing the calculation complexity. In this work, we present RAND-based algorithms, which originate from Gibbs energy minimization, for geochemical CPE problems for closed systems and open systems. The open system problems specify fixed chemical potentials for non-charged species, as in a constant partial CO2 pressure problem, or for charged ionic species, as in a constant pH problem. We showcase the robustness and efficiency of these algorithms using the mineral system Mg-Si-Ca-CO2-H2O because of its relevance to CO2 underground geological storage. The algorithms show quadratic convergence and the coupled tangent plane distance analysis can determine the most stable phase assemblage. The algorithms generate results in agreement with PHREEQC, whereas they are much faster than PHREEQC. The described algorithms can be potentially used for reliable and fast simulation of CO2 storage in geological formations, and of other processes in natural environments involving geochemical equilibrium.

Modelling of kinetic interface sensitive tracers reactive transport in 2D two-phase flow heterogeneous porous media

Fluid-fluid interfacial area plays an important role for mass- and energy-transfer processes across the interface which is relevant in several hydrogeological and engineering applications, e.g. enhanced oil-gas recovery, CO2 storage in geological formations, unconventional geothermal systems, contaminant removal, etc. Kinetic interface sensitive tracers were designed to determine the size of the interface between two fluids by undergoing hydrolysis at the fluid-fluid interface. This study investigates by means of numerical modelling the influence of heterogeneity on the KIS tracer breakthrough curves in six idealized scenarios (S1-S6). It is an extension of the previous work conducted in “one-dimensional” column experiments by Tatomir et al. (2018) [1]. The changes in interfacial area are created by inclusion of heterogeneities at the Darcy-scale. The results show that KIS tracers can be used in two-dimensional experimental setup and can provide information about the size and dynamic evolution of interfacial area. Therefore, this is a first step for the dimensioning of an experimental flume.

Application of the PROMETHEE and VIKOR methods for selecting the most suitable carbon dioxide geological storage option

CO2 storage in geological formations is one of the leading solutions for mitigation greenhouse gas emissions. Types of geological formations that can be used for CO2 storage, that are discussed in this paper are: depleted oil and gas reservoirs, saline aquifers and injection CO2 in partially depleted oil reservoirs for enhanced oil recovery (ЕОР–CO2 method). In order to select the most suitable geological storage of CO2, the ranking of these storage options was performed using two models of multi criteria analysis, PROMETHEE and VIKOR. In this paper are presented an overview of considered criteria (storage capacity, total storage costs, risk assessment costs, storage time dynamics, risk of CO2 leakage from geological formation and risk of CO2 leakage through the well), description of applied multi criteria analysis methods, selection of optimal CO2 storage option and results of their application.

Criteria for CO2 storage in geological formations

CO2 storage in geological formations represents today one of the main new technological solutions for CO2 emission mitigation. Carbon capture and storage technology (CCS) includes capture of anthropogenic CO2 from various emitters, its transportation and injection in different types of geological formations such as: depleted oil and gas reservoirs, saline formations, unmined coal beds, partially depleted oil reservoirs for enhanced oil recovery (EOR-CO2 method) and others. The analysis of numerous criteria that are determining the success of process implementation from a technical, safety, ecological and economic point of view is necessary for considering the optimal CO2 geological storage option. In this paper, an overview of CO2 geological storage types is presented, with an emphasis on criteria for selection of most adequate CO2 storage option. They include geological, physical, thermodynamic, hydrodynamic, techno economic, social criteria, as well as the regulatory issues that are key factors for CCS technology development and further deployment.

Probabilistic modeling and global sensitivity analysis for CO2 storage in geological formations: a spectral approach

• Comprehensive analysis of impact of parametric uncertainties on simulation of CO 2 storage in porous media is performed. • A non-isothermal two-phase two-component flow system is considered. • Rigorous numerical study of the accuracy of the polynomial chaos surrogate model is performed. • A comprehensive global sensitivity analysis is conducted. This work focuses on the simulation of CO 2 storage in deep underground formations under uncertainty and seeks to understand the impact of uncertainties in reservoir properties on CO 2 leakage. To simulate the process, a non-isothermal two-phase two-component flow system with equilibrium phase exchange is used. Since model evaluations are computationally intensive, instead of traditional Monte Carlo methods, we rely on polynomial chaos (PC) expansions for representation of the stochastic model response. A non-intrusive approach is used to determine the PC coefficients. We establish the accuracy of the PC representations within a reasonable error threshold through systematic convergence studies. In addition to characterizing the distributions of model observables, we compute probabilities of excess CO 2 leakage. Moreover, we consider the injection rate as a design parameter and compute an optimum injection rate that ensures that the risk of excess pressure buildup at the leaky well remains below acceptable levels. We also provide a comprehensive analysis of sensitivities of CO 2 leakage, where we compute the contributions of the random parameters, and their interactions, to the variance by computing first, second, and total order Sobol’ indices.

Incorporating Nanoscale Effects into a Continuum-Scale Reactive Transport Model for CO2-Deteriorated Cement.

Wellbore cement deterioration is critical for wellbore integrity and the safety of CO2 storage in geologic formations. Our previous experimental work highlighted the importance of the portlandite (CH)-depleted zone and the surface dissolution zone in the CO2-attacked cement. In this study, we simulated numerically the evolution of the CH-depleted zone and the dissolution of the cement surfaces utilizing a reduced-dimension (1D) reactive transport model. The approach shows that three nanoscale effects are important and had to be incorporated in a continuum-scale model to capture experimental observations: First, it was necessary to account for the fact that secondary CaCO3 precipitation does not fill the pore space completely, with the result that acidic brine continues to diffuse through the carbonated zone to form a CH-depleted zone. Second, secondary precipitation in brine begins via nucleation kinetics, and this could not be described with previous models using growth kinetics alone. Third, our results suggest that the CaCO3 precipitates in the confined pore space are more soluble than those formed in brine. This study provides a new platform for a reduced dimension model for CO2 attack on cement that captures the important nanoscale mechanisms influencing macroscale phenomena in subsurface environments.

Dissolved CO2 Storage in Geological Formations with Low Pressure, Low Risk and Large Capacities

Geological CO2 storage is a mitigation technology to reduce CO2 emissions from fossil fuel combustion. However, major concerns are the pressure increase and saltwater displacement in the mainly targeted deep groundwater aquifers due to injection of supercritical CO2. The suggested solution is storage of CO2 exclusively in the dissolved state. In our exemplary regional case study of the North East German Basin based on a highly resolved temperature and pressure distribution model and a newly developed reactive transport coupling, we have quantified that 4.7 Gt of CO2 can be stored in solution compared to 1.5 Gt in the supercritical state.

A data driven model for the impact of IFT and density variations on CO2 storage capacity in geologic formations

Carbon dioxide (CO2) storage in depleted hydrocarbon reservoirs and deep saline aquifers is one of the most promising solutions for decreasing CO2 concentration in the atmosphere. One of the important issues for CO2 storage in subsurface environments is the sealing efficiency of low-permeable cap-rocks overlying potential CO2 storage reservoirs. Though we focus on the effect of IFT in this study as a factor influencing sealing efficiency or storage capacity, other factors such as interfacial interactions, wettability, pore radius and interfacial mass transfer also affect the mobility and storage capacity of CO2 phase in the pore space. The study of the variation of IFT is however important because the pressure needed to penetrate a pore depends on both the pore size and the interfacial tension. Hence small variations in IFT can affect flow across a large population of pores. A novel model is proposed to find the IFT of the ternary systems (CO2/brine-salt) in a range of temperatures (300–373 K), pressures (50–250 bar), and up to 6 molal salinity applicable to CO2 storage in geological formations through a multi-variant non-linear regression of experimental data. The method uses a general empirical model for the quaternary system CO2/brine-salts that can be made to coincide with experimental data for a variety of solutions. We introduce correction parameters into the model, which compensates for uncertainties, and enforce agreement with experimental data. The results for IFT show a strong dependence on temperature, pressure, and salinity. The model has been found to describe the experimental data in the appropriate parameter space with reasonable precision. Finally, we use the new model to evaluate the effects of formation depth on the actual efficiency of CO2 storage. The results indicate that, in the case of CO2 storage in deep subsurface environments as a global-warming mitigation strategy, CO2 storage capacity increases with reservoir depth.

The Grand Challenge of Carbon Capture and Sequestration

Carbon capture and sequestration (CCS) is designed to reduce atmospheric emissions of greenhouse gases (GHGs). The CCS process captures carbon dioxide (CO2) generated at large-scale industrial sources (power plants, refineries, gasification facilities, etc.) and transports it to an injection site to be permanently stored in the subsurface. With extensive research linking GHG concentrations in the atmosphere to observed changes in global temperature patterns, CCS technology could play an important role in policy efforts to limit the global average temperature rise. Even with the wealth of experience already in place within the oil and gas industry, the obstacles to advancing CCS to the forefront of GHG mitigation technologies remain significant. Large-scale CO2 injection projects remain primarily in the realm of commercial CO2-EOR (enhanced oil recovery) projects. The key challenges to enabling CCS include cost-effective capture and transport of industrial CO2, clear access to pore space for CO2 storage in geologic formations, proven methodologies for demonstrating storage integrity, and dissemination of best practices. SPE members can play a significant role in addressing these challenges. Cost-Effective Capture of Power Sector and Industrial CO2 A major technical challenge facing capture at electric generating facilities is that the CO2 concentration in large-volume flue streams is quite low. Current removal technologies include techniques that apply amines, chilled ammonia, membranes, and ionic liquids to strip the CO2 from the flue stream. However, these technologies were developed to handle smaller-scale operations and higher-CO2-purity streams. When applied to large electric generating plants, process efficiency is reduced, and the energy penalty associated with the capture process drives up costs, increasing the levelized cost of electricity by 50% or more, depending on local factors. Also, to accommodate the substantial volumes of the CO2 and flue gas at full-scale industrial sources, the removal technologies require significant scale up and footprint for deployment. While early movers are developing large-scale capture demonstrations such as SaskPower’s Boundary Dam Project, Southern Company’s Kemper Energy Facility (Fig. 1), and NRG’s Petro Nova Facility, we are still very early on the “learning curve.” Support for more development of next-generation capture technologies and large demonstrations is required to push us down the cost curve. This involves reducing the cost of materials and construction, parasitic costs related to energy for operations, compression, and operation and maintenance costs.

ChemInform Abstract: Mineralization of Carbon Dioxide: A Literature Review

AbstractReview: 223 refs.

Mineralization of Carbon Dioxide: A Literature Review

AbstractResearch on carbon capture and storage has been focused on CO2 storage in geologic formations, with many potential risks. An alternative to conventional geologic storage is carbon mineralization, where CO2 is reacted with metal cations to form carbonate minerals. Mineralization methods can be broadly divided into two categories: in situ and ex situ. In situ mineralization, or mineral trapping, is a component of underground geologic sequestration, in which a portion of the injected CO2 reacts with alkaline rock present in the target formation to form solid carbonate species. In ex situ mineralization, the carbonation reaction occurs above ground, within a separate reactor or industrial process. This literature review is meant to provide an update on the current status of research on CO2 mineralization.

Parallel simulation of fully-coupled thermal-hydro-mechanical processes in CO2 leakage through fluid-driven fracture zones

The safety of CO2 storage in geological formations relies on the integrity of the caprock. However, the elevated fluid pressure during CO2 injection changes the stress states in the caprock, and may lead to reactivate pre-existing fractures or even fracture the caprock. It is necessary to develop an efficient and practical monitor technology to detect and identify CO2 leakage pathways. To this end, we should understand the transport behavior of CO2 coupled with geomechanical effects during injection. In this work, we first developed an efficient parallel fully-coupled thermal-hydro-mechanical simulator to model CO2 transport in porous media. The numerical model was verified through classical problems with analytical solutions. Then, based on this simulator, we investigated the fluid flow behavior when CO2 leakage occurs through fluid-driven fracture zones. We proposed an implicit, physics-based model to simulate the fluid-driven fracturing process by using several practical correlations, including fracturing pressure functions, porosity/permeability–stress relationships. A set of numerical simulations have been conducted by considering various scenarios, such as different injection rates, locations and distributions of fracture zones, and initial fracture permeability. The results show that there are several characteristics can be used to detect CO2 leakage pathways, and it is possible to develop an advanced inverse modeling and monitoring technology to identify leakage locations, times and rates using measured pressure data of permanent downhole gauges and our simulator.

Numerical analyses of the solubility trapping of CO2 storage in geological formations

Numerical analyses are performed to study the fluid dynamic behaviours of the solubility trapping in the context of CO2 storage in deep geological formations. Dissolution of CO2 into the underlying brine increases the density of brine, leading to a gravitational instability. This instability could give rise to the fingering of CO2-rich brine, which would trigger fluid convection and greatly enhance the dissolution rate of CO2. In light of understanding the three-dimensional (3D) effects on the process as well as the effects of caprock slope, both two-dimensional (2D) and 3D simulations are carried out in this study. For the case with no slope, several differences between the 2D and 3D results are observed in the mass transfer process including the CO2 dissolving rate, although the differences between the results are not obvious at the early stages. The analyses of the 3D results with different grid resolutions show that 3D effects could be important in the convective period while they might be negligible in predicting the onset of convection. For the inclined case, the number of fingers is reduced and the interaction of fingers is weakened with the increase of the inclined angle. The results of inclined cases show a clear directional dependence, indicating that 2D simulations cannot be used for the prediction of the solubility trapping when the caprock has an inclined surface.

Bayesian updating via bootstrap filtering combined with data-driven polynomial chaos expansions: methodology and application to history matching for carbon dioxide storage in geological formations

Model calibration and history matching are important techniques to adapt simulation tools to real-world systems. When prediction uncertainty needs to be quantified, one has to use the respective statistical counterparts, e.g., Bayesian updating of model parameters and data assimilation. For complex and large-scale systems, however, even single forward deterministic simulations may require parallel high-performance computing. This often makes accurate brute-force and nonlinear statistical approaches infeasible. We propose an advanced framework for parameter inference or history matching based on the arbitrary polynomial chaos expansion (aPC) and strict Bayesian principles. Our framework consists of two main steps. In step 1, the original model is projected onto a mathematically optimal response surface via the aPC technique. The resulting response surface can be viewed as a reduced (surrogate) model. It captures the model’s dependence on all parameters relevant for history matching at high-order accuracy. Step 2 consists of matching the reduced model from step 1 to observation data via bootstrap filtering. Bootstrap filtering is a fully nonlinear and Bayesian statistical approach to the inverse problem in history matching. It allows to quantify post-calibration parameter and prediction uncertainty and is more accurate than ensemble Kalman filtering or linearized methods. Through this combination, we obtain a statistical method for history matching that is accurate, yet has a computational speed that is more than sufficient to be developed towards real-time application. We motivate and demonstrate our method on the problem of CO2 storage in geological formations, using a low-parametric homogeneous 3D benchmark problem. In a synthetic case study, we update the parameters of a CO2/brine multiphase model on monitored pressure data during CO2 injection.

Application of the Reservoir Simulator MUFITS for 3D Modelling of CO2 Storage in Geological Formations

We propose a new reservoir simulator MUFITS for thermal compositional simulations of underground CO2 storage. We test MUFITS against a benchmarking problem of CO2 storage which is consistent with reservoir conditions in the Johansen formation. We also conduct a series of simulations of CO2 injection using a real-scale geological model of the Johansen formation. We evaluate an optimized location of the injection well for a more complete structural trapping and reduction of potential CO2 leakage out of the formation. The input data for MUFITS, related to the simulations presented in this work, can be downloaded at the simulator website.

CO2 Storage Capacity Assessment in the Deep Saline Aquifers of Southern Israel

CO2 storage in geological formations is one of the techniques proposed for reducing anthropogenic greenhouse gas emissions to the atmosphere. This paper describes the first assessment of effective storage capacity within deep saline aquifers in southern Israel. On the basis of the current CO2 emissions, the State of Israel needs to find storage site(s) for about 5 Gt of CO2, which is the predicted accumulated CO2 emissions for the period between 2025 and 2075. The effective storage capacity of the sedimentary basin in southern Israel, ranging in age from latest Precambrian to Early Cretaceous, was examined based on data from 180 boreholes. Three separated saline aquifers were recognized in the basin, each having its own sealing aquiclude. Each aquiclude is usually thicker than 100 m and will probably prevent CO2 migration upward. The water salinity in these aquifers is usually high (>12,000 ppm Cl−). Capacity calculations are based on the DoE equation (GCO2 = A h ρ E φ), using an effective coefficient (E) of 2%. The results of our study indicate that effective storage potential of the economic zone (800 m to 2,500 m below surface) is about 8.6 Gt, with an additional 10.7 Gt within deeper parts of the aquifers (below the 2,500 m optimum depth).

Uncertainties in practical simulation of CO2 storage

Practical simulation of CO2 storage in geological formations inherently involves decisions concerning relevant physics, upscaling, and numerical modeling. These decisions are unavoidable, since the full problem cannot be resolved by existing numerical approaches. Here, we report on the impact of three distinct approaches to make the problem computationally tractable: reduced physics, upscaling, and non-converged discretizations. Compounding these different strategies, we have used a benchmark study to try to assess the impact of an expert group on the results of the numerical simulations. In order to restrict the scope of the investigation, the geometric and geological description of the storage aquifer was simplified to the greatest extent possible.The different strategies applied to simplify the problem, lead to significantly deviating answers when addressing relevant storage questions. Furthermore, there is room for interpretation when complex simulation results are simplified to the type of higher-level information sought in decision making processes. Our experience leads us to conclude that, important questions relating to CO2 storage cannot be predicted convincingly to satisfactory accuracy with numerical simulation tools, even for highly idealized problems. This emphasizes the need for real-time monitoring and history matching during injection operations.