Long-term Geological Storage Of CO2 Research Articles

Flow-coupled-geomechanical modelling of CO2 transport in depleted shale from a microscopic perspective

Depleted shale reservoirs are the potential candidate sites for long-term geologic storage of CO2. However, understanding of CO2 transport behavior in shale is still a challenge because of the heterogeneity of shale matrix. In this paper, a flow-coupled-geomechanical model is developed for analyzing CO2 transport at the microscale. This model is able to simultaneously capture the geomechanical deformation of organic matter (OM) and inorganic matter (iOM), gas transport in OM and iOM, gas sorption in OM, and both solid and fluid interactions between OM and iOM. The obtained results show that due to shale matrix heterogeneity, i.e., coexistence of OM and iOM, CO2 transport and shale matrix deformation behaviors exhibit regional differences. Specifically, during CO2 injection, pore pressure in OM increases slower, Knudsen number in OM has larger value, apparent permeability in OM is smaller, and volumetric strain in OM is larger. Thus, taking matrix heterogeneity into account is necessary. Moreover, sensitivity analysis indicates that during CO2 injection the apparent permeability of OM changes with both OM and iOM properties while the apparent permeability of iOM only changes with iOM properties. The flow-coupled-geomechanical modelling provides new insights for understanding CO2 transport in depleted shale from a microscopic perspective.

Rapid determination of supercritical CO2 and brine relative permeability using an unsteady-state flow method

Relative permeability of supercritical CO2 (scCO2) and brine was determined in reactive and non-reactive rock cores using a combination of unsteady-state methodology and computed tomography. Experiments were conducted using a medical grade CT scanner to determine saturation using a custom Python script. The saturation and differential pressure across the core were then used to derive four empirical constants to calculate relative permeability. This methodology increases temporal efficiency while reducing experimental complexity. Additionally, we show that the method can be used to determine scCO2 relative permeability in a wide range of lithologies and flow rates, and with the ability to account for matrix dissolution during scCO2 flooding. Plain Language Summary: The ability to capture and store carbon dioxide (CO2) is an important component of efforts to slow climate change. Long-term geologic storage of CO2 requires accurate descriptions of injected CO2 in subsurface rock formations to account for stored volumes and develop adequate risk monitoring. Effectively describing the migration of CO2 injected in underground reservoirs requires an accurate description of how CO2 moves and interacts with the rock. Relative permeability, or the description of how efficiently a fluid moves in a porous media while in the presence of other fluids, is the most utilized tool for describing the competitive flow of fluids. In this study, we detail a modified unsteady-state methodology using computed tomography that provides relative permeability quickly and can be used to analyze heterogenous media. The methodology can be used to describe the impacts of dissolution on CO2 transport through reactive cores, which to the authors knowledge, has not been described in the literature previously.

Study on Two Component Gas Transport in Nanopores for Enhanced Shale Gas Recovery by Using Carbon Dioxide Injection

Injecting carbon dioxide to enhance shale gas recovery (CO2-EGR) is a useful technique that has raised great research interests. Clear understanding of the two-component gas transport mechanisms in shale nanopores is the foundation for the efficient development of shale gas reservoir (SGR) and also the long-term geological storage of CO2. Although extensive studies on single-component gas transport and corresponding models in shale nanopores have been carried out in recent years, limited studies have been conducted on two-component or even multi-component gas transport models in shale nanopores. In this work, the shale nanopores were classified into inorganic and organic nanopores. The corresponding models for two-component gas transport were constructed. Mechanisms including Knudsen diffusion, slip flow, viscous flow, and molecular diffusion are considered in the inorganic pores. In the organic pores, due to existence of adsorption gas, surface diffusion is further considered besides the aforementioned mechanisms. Effects of pressure, temperature, fraction of organic nanopores, and gas concentration were analyzed. Results show that gas apparent permeability is negatively correlated with pressure, and positively correlated with temperature and organic nanopore fraction. As the concentration of CH4 decreases, the apparent permeability of CH4 increases continuously, while the apparent permeability of CO2 decreases. The permeability ratio of CH4 in the total permeability is negatively correlated with pressure and gas concentration ratio. Additionally, the contribution of transport mechanisms to the total gas apparent permeability has been analyzed. It is found that the surface diffusion contributes up to 5.68% to gas apparent permeability under high pressure. The contribution of molecular diffusion can reach up to 88.83% in mesopores under low pressure. Under high pressure and macropores, it contributes less than 1.41%. For all situations, the contribution of viscous flow is more than 46.36%, and its contribution can reach up to 86.07%. Results of this study not only can improve the understanding of two-component gas transport in nanochannels, but also can lay the foundation for more reliable reservoir simulation of CO2-EGR.

A real options approach to production and injection timing under uncertainty for CO2 sequestration in depleted shale gas reservoirs

Depleted shale gas reservoirs may be candidates for conversion to injection wells for the long-term geologic storage of CO2, but the decision to transition from production to injection depends on economic and policy factors that may be uncertain. This paper aims to comprehend the uncertainty inherent to the underlying assumptions of CO2 sequestration and their impact on the injection decision. We view and analyze the production to injection transition decision as a kind of options problem, where the owner of a producing well can choose to exercise the option to stop producing natural gas and start injecting CO2. Our approach integrates a detailed reservoir model for shale-gas production and CO2 injection in the Marcellus shale formation with a multi-period decision problem under uncertainty in future prices for CO2 and produced natural gas. With no uncertainty, the modeling framework is able to identify the optimal timing of the transition to CO2 injection as a function of natural gas prices and a hypothetical CO2 price. We find that a CO2 price of approximately $15 per tonne to be needed in order to incentivize a producer to transition to CO2 injection earlier. If these prices are uncertain, we find that the option to delay CO2 injection has value even when CO2 prices are relatively high and natural gas prices are low, although the option value is highly sensitive to the choice of discount rate and the option value to delay injection is generally very low when CO2 prices are $20/tonne or higher. Our modeling suggests that commitment in carbon pricing regimes is of equal importance to the choice of the price level.

Modeling of Carbon Dioxide Leakage from Storage Aquifers

Long-term geological storage of CO2 in deep saline aquifers offers the possibility of sustaining access to fossil fuels while reducing emissions. However, prior to implementation, associated risks of CO2 leakage need to be carefully addressed to ensure safety of storage. CO2 storage takes place by several trapping mechanisms that are active on different time scales. The injected CO2 may be trapped under an impermeable rock due to structural trapping. Over time, the contribution of capillary, solubility, and mineral trapping mechanisms come into play. Leaky faults and fractures provide pathways for CO2 to migrate upward toward shallower depths and reduce the effectiveness of storage. Therefore, understanding the transport processes and the impact of various forces such as viscous, capillary and gravity is necessary. In this study, a mechanistic model is developed to investigate the influence of the driving forces on CO2 migration through a water saturated leakage pathway. The developed numerical model is used to determine leakage characteristics for different rock formations from a potential CO2 storage site in central Alberta, Canada. The model allows for preliminary analysis of CO2 leakage and finds applications in screening and site selection for geological storage of CO2 in deep saline aquifers.

Assessment of two-phase flow on the chemical alteration and sealing of leakage pathways in cemented wellbores

Wellbore leakage tops the list of perceived risks to the long-term geologic storage of CO2, because wells provide a direct path between the CO2 storage reservoir and the atmosphere. In this paper, we have coupled a two-phase flow model with our original framework that combined models for reactive transport of carbonated brine, geochemistry of reacting cement, and geomechanics to predict the permeability evolution of cement fractures. This addition makes the framework suitable for field conditions in geological storage sites, permitting simulation of contact between cement and mixtures of brine and supercritical CO2.Due to lack of conclusive experimental data, we tried both linear and Corey relative permeability models to simulate flow of the two phases in cement fractures. The model also includes two options to account for the inconsistent experimental observations regarding cement reactivity with two-phase CO2-brine mixtures. One option assumes that the reactive surface area is independent of the brine saturation and the second option assumes that the reactive surface area is proportional to the brine saturation.We have applied the model to predict the extent of cement alteration, the conditions under which fractures seal, the time it takes to seal a fracture, and the leakage rates of CO2 and brine when damage zones in the wellbore are exposed to two-phase CO2-brine mixtures. Initial brine residence time and the initial fracture aperture are critical parameters that affect the fracture sealing behavior. We also evaluated the importance of the model assumptions regarding relative permeability and cement reactivity. Our results illustrate the need to understand how mixtures of carbon dioxide and brine flow through fractures and react with cement to make reasonable predictions regarding well integrity. For example, a reduction in the cement reactivity with two-phase CO2-brine mixture can not only significantly increase the sealing time for fractures but may also prevent fracture sealing.

Influence of SO2 on CO2 storage for CCS technology: Evaluation of CO2/SO2 co-capture

In this work, we determined the influence of SO2 asan impurity in anthropogenic CO2 on carbon capture and storage (CCS) technology. We evaluated the impact on selected injection and storage parameters and the Joule-Thomson coefficient to assess the safety of long-term geological storage of CO2. For this purpose, we obtained new pressure-density-temperature-composition, vapor-liquid-equilibrium, and pressure-speed of sound-temperature-composition experimental data for CO2-rich mixtures containing SO2. To increase the general understanding of the impact of SO2, the compositions cover possible co-capture mixtures, SO2-enriched mixtures, and mixtures similar to industrial emissions. Temperatures and pressures were based on relevant geological storage site values. Our experimental results were used to validate the EOS-CG and PC-SAFT equations of state (EoSs) for CO2+SO2 under the studied CCS conditions. On the understanding that the chemical reactivity effects due to SO2 have not been considered, we concluded that the presence of SO2 is profitable in most of the studied aspects, especially in the case of shallow reservoirs, and that CO2/SO2 co-capture may be considered as an alternative approach to reduce the costs of CO2 purification. Based on the assessment of the impact of 5mol% SO2 in the injected fluid in seven saline aquifers, we determined that the reservoirs that would receive the most benefit were Sleipner, Nagaoka and Frio.

Categorization of Norwegian Continental Shelf Formations in Terms of Geological CO2 Storage Potentials

In the present study, we use data published alongside the Norwegian Petroleum Directorate (NPD) storage atlases to further investigate the storage capacity of 23 formations found in the Norwegian Continental Shelf. Our goal is to categorize the formations according to the main limiting factors for long-term geologic storage of CO2. We conduct the study by defining reasonable injection scenarios and running simulations on grids constructed from the NPD data, which also include the associated averaged rock properties. The use of vertical-equilibrium models allows us to rapidly run a large number of long-term simulations of injection and migration scenarios. The ability to run rapid simulations allows us to optimize injection rates using an adjoint-based nonlinear optimization algorithm. For a given number of wells and set of boundary conditions, we aim to optimize the amount of CO2 injected, subject to limits on long-term leakage and maximum allowed pressures. The outcome allows us to determine whether an aquifer is restricted mainly by long-time leakage across open boundaries, or global pressure buildup. We also provide figures for how much CO2 can be injected before the limitation is reached, subject to the working assumptions and demonstrate how changing these assumptions may influence the result. In particular, the assumed injection time and cost of leakage is discussed.We emphasize that through this study we wish to demonstrate a practical approach to the estimation of realizable storage capacity and illustrate how site-specific operational limitations influence the exploitable storage volume as compared with the initial storage estimates provided by NPD. As the study is based on large-scale averaged data under several simplifying assumptions, the realized storage capacity for each formation may well change if more detailed information, in particular on heterogeneity or more complex fluid-rock interactions, were to be taken into account. However, the use of simplified models to identify realizable storage capacity on the large scale allows us to quickly identify which formations may be best suited for a particular injection scenario.

Techno-economic Issues and Trade-offs for CO2 Purity in CCS Chains

The IMPACTS project has the objective to develop the knowledge base of CO2 quality required for establishing norms and regulations to ensure safe and reliable design, construction and operation of CO2 pipelines and injection equipment, and safe long-term geological storage of CO2. More specifically for this paper, the project sets out to reveal the impacts of relevant impurities in the CO2 stream on the design, operation and costs of the capture, transport and storage infrastructure and to provide recommendations for optimized CO2 quality through techno-economic assessments. The areas covered include corrosion from water content in the CO2 stream in combination with other impurities and the influences of impurities on transport, injection and storage processes and include estimates of the cost of measures to mitigate or prevent these impacts, or of adapting of CCS system design. A specifically designed CCS chain model is used to assess the impacts on a number of reference CCS chains, evaluating economic trade-offs to both understand the full-chain whole-life economics of certain CO2 impurities at different levels and then to potentially optimize a purity specification for various sets of circumstances.

Introduction to the thematic set: Geological storage of CO 2 , gas and energy

This thematic set emerged out of the 3rd EAGE Sustainable Earth Science Conference, held in the picturesque town of Celle in Lower Saxony, Germany, on 13 – 15 October 2015. This conference series was established to develop and promote an emerging group of applied geoscience topics focused on technologies for sustainable use of the subsurface to serve the energy transition; and the focus so far has been mainly on geothermal energy, CO2 storage and energy storage. Inspired by the research emerging from this conference, the conveners proposed a thematic set on the common ground between long-term geological storage of CO2 and the shorter-term cyclic storage of energy. The resulting set of papers is very rewarding, since they capture examples of all these topics and illustrate the complementary nature of subsurface studies on the storage of energy and CO2. We have arranged the set to start with two review papers, followed by three papers on energy storage and then a further three on CO2 storage.

Dissolution sequestration mechanism of CO2 at the Shiqianfeng saline aquifer in the Ordos Basin, northwestern China

This study focused on the target injection layers of deep saline aquifers in the Shiqianfeng Fm. in the Carbon Capture and Sequestration (CCS) Demonstration Projects in the Ordos Basin, northwestern China. The study employed a combination method of experiments and numerical simulation to investigate the dissolution mechanism and impact factors of CO2 in these saline aquifers. The results showed (1) CO2 solubility in different types of water chemistry were shown in ascending order: MgCl2-type water < CaCl2-type water < Na2SO4-type water < NaCl-type water < Na2CO3-type water < distilled water. These results were consistent with the calculated results undertaken by TOUGHREACT with about 5% margin of error. CO2 solubility of Shiqianfeng Fm. saline was 1.05 mol/L; (2) compared with distilled water, the more complex the water’s chemical composition, the greater the increase in HCO3 −concentration. While the water’s composition was relatively simple, the tested water’s HCO3 −concentrations were in close accord with the calculated value undertaken by the TOUGHREACT code, and the more complex the water’s composition, the poorer the agreement was, probably due to the complex and unstable HCO3 − complicating matters when in an aqueous solution system including both tested HCO3 −concentration and calculated HCO3 −concentration; (3) the CO2 solubility in the saline at the temperature conditions of 55 °C and 70 °C were 1.17 and 1.02 mol/L. When compared with the calculated value of 1.20 and 1.05 mol/L, they were almost the same with only 1 and 3% margin of error; concentrations of HCO3 − were 402.73 mg/L (0.007 mol/L) and 385.65 mg/L (0.006 mol/L), while the simulation results were 132.16 mg/L (0.002 mol/L) and 128.52 mg/L (0.002 mol/L). From the contrast between the tested data and the calculated data undertaken by the TOUGHREACT code, it was shown that TOUGHRACT code could better simulate the interaction between saline and CO2 in the dissolution sequestration capacity. Therefore, TOUGHREACT code could be used for the inter-process prediction of CO2 long-term geological storage of CO2; (4) The Ca2+ concentration and SO4 2−concentration in saline water had less effect on the solubility of CO2 and HCO3 −concentration. In addition, TDS and pH values of saline affected not only the solubility of CO2, but also the conversion of CO2 to HCO3 − due to that they can affect the activity and acid-base balance. So in fact, we just need to consider that the TDS and pH values are main impact factors in the dissolution sequestration capacity of CO2 geological sequestration in deep saline aquifers.

Simulating in-zone chemistry changes from injection time to longer periods of CO2 storage

Geochemical reactions can play important role in the long-term geological storage of CO2 in sites where the target formations have reactive minerals. Although the use of batch models (experimental or theoretical) is expedient, it leaves questions unanswered about how to interpret or predict field-scale injection over long time periods. In this study we present results of coupled multiphase, multicomponent reactive transport simulation using geochemistry data derived from Cranfield site, Mississippi, USA, a site that has long been used for carbon sequestration RD however, more CO2 is trapped in solution.

Robust simulation of sharp-interface models for fast estimation of CO2 trapping capacity in large-scale aquifer systems

Modeling geological carbon storage represents a new and substantial challenge for the subsurface geosciences. To increase understanding and make good engineering decisions, containment processes and large-scale storage operations must be simulated in a thousand-year perspective. Large differences in spatial and temporal scales make it prohibitively expensive to compute the fate of injected CO2 using traditional 3D simulators. Instead, accurate forecast can be computed using simplified models that are adapted to the specific setting of the bouyancy-driven migration of the light fluid phase. This paper presents a family of vertically integrated models for studying the combined large-scale and long-term effects of structural, residual, and solubility trapping of CO2. The models are based on an assumption of a sharp interface separating CO2 and brine and can provide a detailed inventory of the injected CO2 volumes over periods of thousands of years within reasonable computational time. To be compatible with simulation tools used in industry, the models are formulated in a black-oil framework. The models are implemented in MRST-co2lab, which is an open community software developed especially to study and optimize large-scale, long-term geological storage of CO2. The resulting simulators are fully implicit and handle input from standard geomodeling tools.

IMPACTS: Economic Trade-offs for CO2 Impurity Specification

The IMPACTS project has a stated broad objective to develop the knowledge base of CO2 quality required for establishing norms and regulations to ensure safe and reliable design, construction and operation of CO2 pipelines and injection equipment, and safe long-term geological storage of CO2. More specifically for this paper, the project sets out to reveal the impacts of relevant impurities in the CO2 stream on the design, operation and costs of the capture, transport and storage infrastructure and to provide recommendations for optimized CO2 quality through techno-economic assessments (amongst other considerations). This paper gives an overview of the work being carried out to investigate the impact of CO2 quality in various areas including corrosion, water content in the CO2 stream and the injection and storage processes. The paper reports on the derived impacts of the above mentioned aspects of CO2 quality. These impacts are combined with estimates of the cost of measures to mitigate or prevent these impacts from affecting the operation of the CCS system, or of adapting of CCS system design. Thus, the impacts can be set out as a set of cost functions relating to Capex and Opex and including the effects of overall availability and process efficiency changes. A specifically designed CCS chain model is used to assess the impacts on a number of reference CCS chains, carrying out comparative economic trade-offs to both understand the full- chain whole-life economics of certain CO2 impurities at different levels and then to potentially optimize a purity specification for various sets of circumstances.

Engineered CO2 injection: The use of surfactants for enhanced sweep efficiency

Poor CO2 displacement efficiency can exacerbate hydro-chemo-mechanically coupled phenomena in CO2 storage reservoirs, increase the area affected by CO2 in the reservoir, and negatively impact the long-term geological storage of CO2. The injection of CO2 can be engineered using surfactants to improve displacement efficiency. Pendant and sessile drop tests show that a surfonic copolymer decreases the interfacial tension γfl and increases the contact angle θ under reservoir conditions. The combined changes in surface tension and contact angle have a pronounced effect on the capillary factor γfl·cosθ. Injection tests using micro-models and pore network simulations show that a smaller capillary factor transforms the displacement pattern and enhances the pore-scale sweep efficiency of CO2, surpassing 40% in 2-D applications. Surfactant cost may offset the technical advantages identified in this study.

Overview, Status, and Future of the Fort Nelson CCS Project

The Plains CO2 Reduction Partnership, led by the Energy & Environmental Research Center, and Spectra Energy Transmission (SET) are investigating the feasibility of a carbon capture and storage project to mitigate carbon dioxide (CO2) emissions produced by SET's Fort Nelson Gas Plant in British Columbia, Canada. The project applies an integrated philosophy combining geologic characterization, modeling, risk assessment, and monitoring into an iterative process, producing superior-quality results during the project feasibility and development periods. Results to date suggest that the geology and hydrogeology of the project area are amenable to large-scale, long-term geologic storage of CO2.

In Situ Determination of Interfacial Energies between Heterogeneously Nucleated CaCO3 and Quartz Substrates: Thermodynamics of CO2 Mineral Trapping

The precipitation of carbonate minerals--mineral trapping--is considered one of the safest sequestration mechanisms ensuring long-term geologic storage of CO(2). However, little is known about the thermodynamic factors controlling the extent of heterogeneous nucleation at mineral surfaces exposed to the fluids in porous reservoirs. The goal of this study is to determine the thermodynamic factors controlling heterogeneous nucleation of carbonate minerals on pristine quartz (100) surfaces, which are assumed representative of sandstone reservoirs. To probe CaCO(3) nucleation on quartz (100) in solution and with nanoscale resolution, an in situ grazing incidence small-angle X-ray scattering technique has been utilized. With this method, a value of α' = 36 ± 5 mJ/m(2) for the effective interfacial free energy governing heterogeneous nucleation of CaCO(3) has been obtained by measuring nucleation rates at different solution supersaturations. This value is lower than the interfacial energy governing calcite homogeneous nucleation (α ≈ 120 mJ/m(2)), suggesting that heterogeneous nucleation of calcium carbonate is favored on quartz (100) at ambient pressure and temperature conditions, with nucleation barriers between 2.5% and 15% lower than those expected for homogeneous nucleation. These observations yield important quantitative parameters readily usable in reactive transport models of nucleation at the reservoir scale.

In situ XRD study of Ca2+ saturated montmorillonite (STX-1) exposed to anhydrous and wet supercritical carbon dioxide

Reactions involving supercritical carbon dioxide (scCO2) and a calcium saturated dioctahedral smectite (Ca-STX-1) were examined by in situ high-pressure X-ray diffraction over a range of temperatures (50–100°C) and pressures (90, 125, and 180bar) relevant to long-term geologic storage of CO2. Exposure of Ca-STX-1 containing one water of hydration (1W) to anhydrous scCO2 at 50°C and 90bar produced an immediate increase of ∼0.8Å in the d001 basal reflection that was sustained for the length of the experiment (∼44h). Higher ordered basal reflections displayed similar shifts. Following depressurization, positions of basal reflections and FWHM values (d001) returned to initial values, with no measurable modification to the clay structure or water content. Similar results were obtained for tests conducted at 50°C and higher pressures (125 and 180bar). Exposure of Ca-STX-1 containing two waters of hydration (2W) to scCO2 resulted in a decrease in the d001 reflection from 14.48Å to 12.52Å, after pressurization, indicating a partial loss of interlayer water. In addition, the hydration state of the clay became more homogeneous during contact with anhydrous scCO2 and after depressurization. In the presence of scCO2 and water, the clay achieved a 3W hydration state, based on a d001 spacing of 18.8Å. In contrast to scCO2, comparable testing with N2 gas indicated trivial changes in the d001 series regardless of hydration state (1W or 2W). In the presence of free water and N2, the basal spacing for the Ca-STX-1 expanded slightly, but remained in the 2W hydration state. The experiments show that potential collapse or expansion of the interlayer spacing depends on the initial hydration state of the clay and scCO2, where 1W clay is stable but ≥2W layer clay loses water when exposed to anhydrous CO2. Consequently, the implications of this study depend upon the depth of the caprock. If the caprock is quite deep, then the 1W hydration state is favored and the introduction of dry CO2 could actually help seal the formation. If the caprock is located closer to the surface where 2W or 3W montmorillonite is the predominant form then the introduction of dry CO2 should result in the creation of permeability. Further, these experiments indicate that scCO2 can become intercalated within hydrated clays under conditions proposed for geologic storage of CO2 and act as secondary CO2 traps.

The mechanical behavior of anhydrite and the effect of deformation on permeability development–Implications for caprock integrity during geological storage of CO2

Maintaining caprock integrity is key to long-term geological storage of CO2, as large-scale structural trapping below a top seal is one of the most important storage mechanisms. Evaporite sequences, such as anhydrite, form the caprock of many depleted oil and gas reservoirs, as well as several current CCS sites and natural CO2 analogues. This paper is based on two studies by Hangx et al. on the mechanical and volumetric (permeability) behavior of Zechstein anhydrite.