Robust simulation of sharp-interface models for fast estimation of CO<Subscript>2</Subscript> 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.     

Modeling, parameterization and evaluation of monitoring methods for CO2 storage in deep saline formations: the CO2-MoPa project

Capture and geological sequestration of CO₂ from large industrial sources is considered a measure for reducing anthropogenic emissions of CO₂ and thus mitigating climate change. One of the main storage options proposed are deep saline formations, as they provide the largest potential storage capacities among the geologic options. A thorough assessment of this type of storage site therefore is required. The CO₂-MoPa project aims at contributing to the dimensioning of CO₂ storage projects and to evaluating monitoring methods for CO₂ injection by an integrated approach. For this, virtual, but realistic test sites are designed geometrically and fully parameterized. Numerical process models are developed and then used to simulate the effects of a CO₂ injection into the virtual test sites. Because the parameterization of the virtual sites is known completely, investigation as well as monitoring methods can be closely examined and evaluated by comparing the virtual monitoring result with the simulation. To this end, the monitoring or investigation method is also simulated, and the (virtual) measurements are recorded and evaluated like real data. Application to a synthetic site typical for the north German basin showed that pressure response has to be evaluated taking into account the layered structure of the storage system. Microgravimetric measurements are found to be promising for detecting the CO₂ phase distribution. A combination of seismic and geoelectric measurements can be used to constrain the CO₂ phase distribution for the anticline system used in the synthetic site.     

A preliminary evaluation of carbon dioxide storage capacity in unmineable coalbeds in China

In this study, CO₂ storage capacity in unmineable coalbeds in China at depths of 1,000–2,000 m has been evaluated using the methodology recommended by CSLF. This evaluation is one part of the countrywide CO₂ storage capacity evaluations in China, initiated by the Chinese Ministry of Land and Resources. This level of CO₂ storage capacity evaluation gives a rough scale of assessment with the least site-specific detail. The results show that there is a storage capacity of 98.81 × 10⁸ t CO₂ in coalbeds buried at a depth range of 1,000–2,000 m and 4.26 × 10¹² m³ additional coalbed methane can be recovered by CO₂ injection. These results appear to show great potential and an attractive economic perspective of CO₂ storage in unmineable coalbeds in China. Another part of this study is to classify the potential coalbed basins based on CO₂ storage capacity and storage capacity per unit area. The study results reveal the distribution of the most potential basins for large-scale CO₂ storage and the best economic basins for early CO₂ storage in the future.     

Optimal selection of different CCS technologies under CO2 reduction targets

In China, carbon capture and storage (CCS) is recognized as one of the most promising technologies through which to achieve a large reduction in CO₂ emissions in future. The choice among different CCS technologies is critical for large-scale applications. With the aim of developing instructive policy suggestions for CCS development, this study proposed an interval programming model to select the optimal CCS technology among the different CCS technologies available in China. The analysis results indicate that the selection of CO₂ capture technologies should be based on the actual situation of the project and industry being targeted. If the government implements mandatory CO₂ emission reductions, storage in deep saline aquifers is the optimal choice for CO₂ sequestration when oil prices are low and the number of available CO₂ emission permits is large. In contrast, enhanced oil recovery is the optimal choice when oil prices increase and the availability of CO₂ emission permits decreases. It is critical that the government reduce the operating cost and the cost of CO₂ capture in particular.

     

Appraisal of CO2 storage potential in compressional hydrocarbon-bearing basins: Global assessment and case study in the Sichuan Basin (China)

Carbon capture and storage (CCS) has been proposed as a potential technology to mitigate climate change. However, there is currently a huge gap between the current global deployment of this technology and that which will be ultimately required. Whilst CO₂ can be captured at any geographic location, storage of CO₂ will be constrained by the geological storage potential in the area the CO₂ is captured. The geological storage potential can be evaluated at a very high level according to the tectonic setting of the target area. To date, CCS deployment has been restricted to more favourable tectonic settings, such as extensional passive margin and post-rift basins and compressional foreland basins. However, to reach the adequate level of deployment, the potential for CCS of regions in different tectonic settings needs to be explored and assessed worldwide. Surprisingly, the potential of compressional basins for carbon storage has not been universally evaluated according to the global and regional carbon emission distribution. Here, we present an integrated source-to-sink analysis tool that combines comprehensive, open-access information on basin distribution, hydrocarbon resources and CO₂ emissions based on geographical information systems (GIS). Compressional settings host some of the most significant hydrocarbon-bearing basins and 36% of inland CO₂ emissions but, to date, large-scale CCS facilities in compressional basins are concentrated in North America and the Middle East only. Our source-to-sink tool allows identifying five high-priority regions for prospective CCS development in compressional basins: North America, north-western South America, south-eastern Europe, the western Middle East and western China. We present a study of the characteristics of these areas in terms of CO₂ emissions and CO₂ storage potential. Additionally, we conduct a detailed case-study analysis of the Sichuan Basin (China), one of the compressional basins with the greatest CO₂ storage potential. Our results indicate that compressional basins will have to play a critical role in the future of CCS if this technology is to be implemented worldwide.     

Review: The potential impact of underground geological storage of carbon dioxide in deep saline aquifers on shallow groundwater resources

Underground geological storage of CO₂ in deep saline aquifers is considered for reducing greenhouse gases emissions into the atmosphere. However, some issues were raised with regard to the potential hazards to shallow groundwater resources from CO₂ leakage, brine displacement and pressure build-up. An overview is provided of the current scientific knowledge pertaining to the potential impact on shallow groundwater resources of geological storage of CO₂ in deep saline aquifers, identifying knowledge gaps for which original research opportunities are proposed. Two main impacts are defined and discussed therein: the near-field impact due to the upward vertical migration of free-phase CO₂ to surficial aquifers, and the far-field impact caused by large-scale displacement of formation waters by the injected CO₂. For the near-field, it is found that numerical studies predict possible mobilization of trace elements but concentrations are rarely above the maximum limit for potable water. For the far-field, numerical studies predict only minor impacts except for some specific geological conditions such as high caprock permeability. Despite important knowledge gaps, the possible environmental impacts of geological storage of CO₂ in deep saline aquifers on shallow groundwater resources appears to be low, but much more work is required to evaluate site specific impacts.     

Geological modeling and simulation of CO2 injection in the Johansen formation

The Johansen formation is a candidate site for large-scale CO₂ storage offshore of the south-western coast of Norway. An overview of the geology for the Johansen formation and neighboring geological formations is given, together with a discussion of issues for geological and geophysical modelling and integrated fluid flow modelling. We further describe corresponding simulation models. Major issues to consider are capacity estimation and processes that could potentially cause CO₂ to leak out of the Johansen formation and into the formations above. Currently, these issues can only be investigated through numerical simulation. We consider the effect of different boundary conditions, sensitivity with respect to vertical grid refinement and permeability/transmisibility data, and the effect of residual gas saturations, since these strongly affect the CO₂-plume distribution. The geological study of the Johansen formation is performed based on available seismic and well data. Fluid simulations are performed using a commercial simulator capable of modelling CO₂ flow and transport by simple manipulation of input files and data. We provide details for the data and the model, with a particular focus on geology and geometry for the Johansen formation. The data set is made available for download online.     

Selection of coals of different maturities for CO2 Storage by modelling of CH4 and CO2 adsorption isotherms

CO₂ injection in unmineable coal seams could be one interesting option for both storage and methane recovery processes. The objective of this study is to compare and model pure gas sorption isotherms (CO₂ and CH₄) for well-characterised coals of different maturities to determine the most suitable coal for CO₂ storage. Carbon dioxide and methane adsorption on several coals have been investigated using a gravimetric adsorption method. The experiments were carried out using both CO₂ and CH₄ pure gases at 25 °C from 0.1 to 5 MPa (1 to 50 bar). The experimental results were fitted using Temkin's approach but also with the corrected Langmuir's and the corrected Tóth's equations. The two last approaches are more accurate from a thermodynamical point of view, and have the advantage of taking into account the fact that experimental data (isotherms) correspond to excess adsorption capacities. These approaches allow better quantification of the adsorbed gas. Determined CO₂ adsorption capacities are from 0.5 to 2 mmol/g of dry coal. Modelling provides also the affinity parameters of the two gases for the different coals. We have shown these parameters determined with adsorption models could be used for classification and first selection of coals for CO₂ storage. The affinity ratio ranges from a value close to 1 for immature coals to 41 for high rank coals like anthracites. This ratio allows selecting coals having high CO₂ adsorption capacities. In our case, the modelling study of a significant number of coals from various ranks shows that anthracites seem to have the highest CO₂ storage capacities. Our study provides high quality affinity parameters and values of CO₂ and CH₄ adsorption capacities on various coals for the future modelling of CO₂ injection in coal seams.     

Site characterization for CO<Subscript>2</Subscript> geologic storage and vice versa: the Frio brine pilot,Texas, USA as a case study

Careful site characterization is critical for successful geologic storage of carbon dioxide (CO₂) because of the many physical and chemical processes impacting CO₂ movement and containment under field conditions. Traditional site characterization techniques such as geological mapping, geophysical imaging, well logging, core analyses, and hydraulic well testing provide the basis for judging whether or not a site is suitable for CO₂ storage. However, only through the injection and monitoring of CO₂ itself can the coupling between buoyancy flow, geologic heterogeneity, and history-dependent multi-phase flow effects be observed and quantified. CO₂ injection and monitoring can therefore provide a valuable addition to the site-characterization process. Additionally, careful monitoring and verification of CO₂ plume development during the early stages of commercial operation should be performed to assess storage potential and demonstrate permanence. The Frio brine pilot, a research project located in Dayton, Texas (USA) is used as a case study to illustrate the concept of an iterative sequence in which traditional site characterization is used to prepare for CO₂ injection and then CO₂ injection itself is used to further site-characterization efforts, constrain geologic storage potential, and validate understanding of geochemical and hydrological processes. At the Frio brine pilot, in addition to traditional site-characterization techniques, CO₂ movement in the subsurface is monitored by sampling fluid at an observation well, running CO₂-saturation-sensitive well logs periodically in both injection and observation wells, imaging with crosswell seismic in the plane between the injection and observation wells, and obtaining vertical seismic profiles to monitor the CO₂ plume as it migrates beyond the immediate vicinity of the wells. Numerical modeling plays a central role in integrating geological, geophysical, and hydrological field observations.     

Modeling the effects of completion techniques and formation heterogeneity on CO2 sequestration in shallow and deep saline aquifers

This work studied the effect of completion techniques and reservoir heterogeneity on CO₂ storage and injectivity in saline aquifers using a compositional reservoir simulator, CMG-GEM. Two reservoir models were built based on the published data to represent a deep saline aquifer and a shallow aquifer. The effect of various completion conditions on CO₂ storage was then discussed, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location, and length. The heterogeneity effect was addressed by considering three parameters: mean permeability, the vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using iSIGHT software (design of experiments) to determine the dominant factors affecting CO₂ storage capacity and injectivity. Simulation results show that the most favorable option is the perforation of all layers with horizontal wells 250–300 m long set in the upper layers. Mean permeability has the most effect on CO₂ storage capacity and injectivity; k _v/k _h affects CO₂ injectivity storage capacity more than permeability variation, V _k. More CO₂ can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.     

CO2 geological storage: The environmental mineralogy perspective

Geological storage of carbon dioxide (CO₂) is one of the options envisaged for mitigating the environmental consequences of anthropogenic CO₂ increases in the atmosphere. The general principle is to capture carbon dioxide at the exhaust of power plants and then to inject the compressed fluid into deep geological formations. Before implementation over large scales, it is necessary to assess the efficiency of the process and its environmental consequences. The goal of this paper is to discuss some environmental mineralogy research perspectives raised by CO₂ geological storage.     

Impacts of mineralogical compositions on different trapping mechanisms during long-term CO<Subscript>2</Subscript> storage in deep saline aquifers

Deep saline aquifers in sedimentary basins are considered to have the greatest potential for CO₂ geological storage in order to reduce carbon emissions. CO₂ injected into a saline sandstone aquifer tends to migrate upwards toward the caprock because the density of the supercritical CO₂ phase is lower than that of formation water. The accumulated CO₂ in the upper portions of the reservoir gradually dissolves into brine, lowers pH and changes the aqueous complexation, whereby induces mineral alteration. In turn, the mineralogical composition could impose significant effects on the evolution of solution, further on the mineralized CO₂. The high density of aqueous phase will then move downward due to gravity, give rise to “convective mixing,” which facilitate the transformation of CO₂ from the supercritical phase to the aqueous phase and then to the solid phase. In order to determine the impacts of mineralogical compositions on trapping amounts in different mechanisms for CO₂ geological storage, a 2D radial model was developed. The mineralogical composition for the base case was taken from a deep saline formation of the Ordos Basin, China. Three additional models with varying mineralogical compositions were carried out. Results indicate that the mineralogical composition had very obvious effects on different CO₂ trapping mechanisms. Specific to our cases, the dissolution of chlorite provided Mg²⁺ and Fe²⁺ for the formation of secondary carbonate minerals (ankerite, siderite and magnesite). When chlorite was absent in the saline aquifer, the dominant secondary carbon sequestration mineral was dawsonite, and the amount of CO₂ mineral trapping increased with an increase in the concentration of chlorite. After 3000 years, 69.08, 76.93, 83.52 and 87.24 % of the injected CO₂ can be trapped in the solid (mineral) phase, 16.05, 11.86, 8.82 and 6.99 % in the aqueous phase, and 14.87, 11.21, 7.66 and 5.77 % in the gas phase for Case 1 through 4, respectively.     

Factors affecting CO2 storage capacity and efficiency with water withdrawal in shallow saline aquifers

Carbon sequestration in shallow aquifers can be facilitated by water withdrawal. The factors that optimize the injection/withdrawal balance to minimize potential environmental impacts have been studied, including reservoir size, well pattern, injection rate, reservoir heterogeneity, anisotropy ratio, and permeability sequence. The effects of these factors on CO₂ storage capacity and efficiency were studied using a compositional simulator Computer Modeling Group-General Equation of State Model, which modeled features including residual gas trapping, CO₂ solubility, and mineralization reactions. Two terms, storage efficiency and CO₂ relative breakthrough time, were introduced to better describe the problem. The simulation results show that simultaneous water withdrawal during CO₂ injection greatly improves CO₂ storage capacity and efficiency. A certain degree of heterogeneity or anisotropy benefits CO₂ storage. A high injection rate favors storage capacity, but reduces the storage efficiency and CO₂ breakthrough time, which in turn limits the total amount of CO₂ injected.     

Can the long-term potential for carbonatization and safe long-term CO2 storage in sedimentary formations be predicted?

A sedimentary formation perturbated by supercritical CO₂ reacts by dissolving primary minerals and forming new secondary phases. In this process CO₂ may be trapped in stable carbonate minerals and may thereby be immobilized for long time spans. The potential for mineral trapping can be estimated by solving kinetic expressions for the reservoir minerals and possible secondary phases. This is, however, not trivial as kinetic data are uncertain or even lacking for the minerals of interest. Here, the rate equations most commonly used for CO₂ storage simulations have been solved, and the rate parameters varied, to obtain sensitivity on the total amount of CO₂ stored as mineral carbonate. As various expressions are in use to estimate growth rates of secondary carbonates, three formulations were compared, including one taking into account mineral nucleation preceding growth. The sensitivity studies were done on two systems, the Utsira Sand being representative for a cold quartz-rich sand (37 °C, 100 bar CO₂), and the Gulf Coast Sediment, being representative for a medium temperature quartz–plagioclase-rich system (75 °C, 300 bar CO₂).The simulations showed that the total predicted CO₂ mineral storage is especially sensitive to the choice of growth rate model and the reactive surface area. The largest sensitivity was found on α, fraction of total surface area available for reactions, with a reduction of one order of magnitude for all reacting phases leading to 3–4 times lower predicted CO₂ mineral storage. Because the reactive surface area is highly uncertain for natural systems, the range in predicted results may be even larger. The short-term predictions (<100–1000 a), such as the onset of carbonate growth, were highly sensitive to nucleation and growth rates. Moreover, the type of carbonate minerals formed was shown to be model dependent, with the simplest model predicting an unlikely carbonate assemblage at low temperature (i.e., formation of dolomite at 37 °C). Therefore, to use kinetic models to upscale short-term (<months) laboratory experiments in time, to identify the past reactions and physical conditions of natural CO₂ storage analogues, and finally to predict the potential for CO₂ trapping in existing and future storage projects, more knowledge has to be collected, especially on the reactive surface area of CO₂ storage reservoirs, and on the rate of secondary carbonate nucleation and growth.     

Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin,China

Deep saline aquifers still remain a significant option for the disposal of large amounts of CO₂ from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO₂ plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO₂ gas saturation and mass fraction of dissolved CO₂ in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO₂ injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO₂ injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO₂ plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO₂–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO₂ injection scheme still requires pursuance of further studies.     

On the interaction of pure and impure supercritical CO2 with rock forming minerals in saline aquifers: An experimental geochemical approach

The aim of this experimental study was to evaluate and compare the geochemical impact of pure and impure CO₂ on rock forming minerals of possible CO₂ storage reservoirs. This geochemical approach takes into account the incomplete purification of industrial captured CO₂ and the related effects during injection, and provides relevant data for long-term storage simulations of this specific greenhouse gas. Batch experiments were conducted to investigate the interactions of supercritical CO₂, brine and rock-forming mineral concentrates (albite, microcline, kaolinite, biotite, muscovite, calcite, dolomite and anhydrite) using a newly developed experimental setup. After up to 42 day (1000 h) experiments using pure and impure supercritical CO₂ the dissolution and solution characteristics were examined by XRD, XRF, SEM and EDS for the solid, and ICP–MS and IC for the fluid reactants, respectively. Experiments with mixtures of supercritical CO₂ (99.5 vol.%) and SO₂ or NO₂ impurities (0.5 vol.%) suggest the formation of H₂SO₄ and HNO₃, reflected in pH values between 1 and 4 for experiments with silicates and anhydrite and between 5 and 6 for experiments with carbonates. These acids should be responsible for the general larger amount of cations dissolved from the mineral phases compared to experiments using pure CO₂. For pure CO₂ a pH of around 4 was obtained using silicates and anhydrite, and 7–8 for carbonates. Dissolution of carbonates was observed after both pure and impure CO₂ experiments. Anhydrite was corroded by approximately 50 wt.% and gypsum precipitated during experiments with supercritical CO₂ + NO₂. Silicates do not exhibit visible alterations during all experiments but released an increasing amount of cations in the reaction fluid during experiments with impure CO₂. Nonetheless, precipitated secondary carbonates could not be identified.     

CO<Subscript>2</Subscript> Air–Sea Exchange due to Calcium Carbonate and Organic Matter Storage,and its Implications for the Global Carbon Cycle

Release of CO₂ from surface ocean water owing to precipitation of CaCO₃ and the imbalance between biological production of organic matter and its respiration, and their net removal from surface water to sedimentary storage was studied by means of a quotient θ = (CO₂ flux to the atmosphere)/(CaCO₃ precipitated). θ depends not only on water temperature and atmospheric CO₂ concentration but also on the CaCO₃ and organic carbon masses formed. In CO₂ generation by CaCO₃ precipitation, θ varies from a fraction of 0.44 to 0.79, increasing with decreasing temperature (25 to 5°C), increasing atmospheric CO₂ concentration (195–375 ppmv), and increasing CaCO₃ precipitated mass (up to 45% of the initial DIC concentration in surface water). Primary production and net storage of organic carbon counteracts the CO₂ production by carbonate precipitation and it results in lower CO₂ emissions from the surface layer. When atmospheric CO₂ increases due to the ocean-to-atmosphere flux rather than remaining constant, the amount of CO₂ transferred is a non-linear function of the surface layer thickness because of the back-pressure of the rising atmospheric CO₂. For a surface ocean layer approximated by a 50-m-thick euphotic zone that receives input of inorganic and organic carbon from land, the calculated CO₂ flux to the atmosphere is a function of the CaCO₃ and C_org net storage rates. In general, the carbonate storage rate has been greater than that of organic carbon. The CO₂ flux near the Last Glacial Maximum is 17 to 7×10¹² mol/yr (0.2–0.08 Gt C/yr), reflecting the range of organic carbon storage rates in sediments, and for pre-industrial time it is 38–42×10¹² mol/yr (0.46–0.50 Gt C/yr). Within the imbalanced global carbon cycle, our estimates indicate that prior to anthropogenic emissions of CO₂ to the atmosphere the land organic reservoir was gaining carbon and the surface ocean was losing carbon, calcium, and total alkalinity owing to the CaCO₃ storage and consequent emission of CO₂. These results are in agreement with the conclusions of a number of other investigators. As the CO₂ uptake in mineral weathering is a major flux in the global carbon cycle, the CO₂ weathering pathway that originates in the CO₂ produced by remineralization of soil humus rather than by direct uptake from the atmosphere may reduce the relatively large imbalances of the atmosphere and land organic reservoir at 10²–10⁴-year time scales.     

四川盆地理论CO_2地质利用与封存潜力评估

结合CO_2地质利用与封存技术机理,在国际权威潜力评估公式的基础上,系统地提出了适合中国地质背景的次盆地尺度CO_2封存潜力评估方法及关键参数取值。同时,以四川盆地为例,依次开展了枯竭油田地质封存与CO_2强化石油开采、枯竭气田与CO_2强化采气、不可采煤层地质封存与CO_2驱替煤层气,以及咸水层地质封存技术的CO_2地质封存潜力。结果表明,四川盆地利用深部咸水层与枯竭天然气田CO_2地质封存潜力最大,期望值分别达154.20×10~8t和53.73×10~8t。其中,枯竭天然气田因成藏条件好、勘探程度高、基础建设完善,为四川盆地及其周边利用枯竭气田CO_2地质封存技术实现低碳减排提供了早期示范机会。CO_2地质利用与封存潜力评估方法,对进一步开展全国次盆地尺度理论封存潜力评估与工程规划具有重要意义。