CO2 Storage In Saline Aquifers Research Articles

Spatiotemporal X-Ray Imaging of Neat and Viscosified CO2 in Displacement of Brine-Saturated Porous Media

Summary CO2 storage in saline aquifers may contribute to a 90% share in preventing emissions to the atmosphere. Due to low CO2 viscosity at the subsurface often found in supercritical (sc) conditions, the injected CO2 may spread quickly at the formation top and increase the probability of leakage. This work relates to improved CO2 storage in saline aquifers by effective viscosification of the sc-CO2 at very low concentrations of engineered oligomers and the effectiveness of slug injection of viscosified CO2 (vis-CO2). We present the results from X-ray computed tomography (CT) imaging to advance the understanding of two-phase CO2-brine flow in porous media and firmly establish the transport mechanisms. X-ray CT imaging of displacement experiments is conducted to quantify the in-situ sc-CO2 saturation spatiotemporally. In neat CO2 injection, gravity override and adverse mobility ratio may result in early breakthrough and low sweep efficiency. We find cumulative brine production from the fraction collector to be lower than X-ray CT imaging at 2 pore volume (PV) injection. The difference between the two is attributed to the solubility of the produced water in the produced CO2 at atmospheric pressure. We show that when the solubility is accounted for, there is a good agreement between direct measurements and in-situ saturation results. There are three reports (two by the same group) that oligomers of 1-decene (O1D) with six repeat units may have marginal CO2 viscosification. The majority of published work by other groups shows that O1D with six repeat units and higher are effective CO2 viscosifiers. In the past, we have demonstrated the effectiveness of an O1D in the displacement of brine by CO2 at a concentration of 1.5 wt%. The effectiveness is examined and identified by three different methods. In this work, we show that the same oligomer is effective at a low concentration of 0.6 wt%. The oligomer slows the breakthrough by 1.6 times and improves the brine production by 34% in the horizontal orientation. X-ray CT imaging results reveal that such a large effect may be from the increase in the interfacial elasticity. We also show that there is no need for continuous injection of the oligomer. A slug of 0.3 PV injection (PVI) of vis-CO2 followed by neat CO2 injection has the same effectiveness as the continuous injection of the vis-CO2. In this work, we also demonstrate the effectiveness of a new engineered molecule at 0.3 wt% that may increase residual trapping by about 35%. The combination of mobility control and residual brine saturation reduction is expected to improve CO2 storage by effective viscosification with low concentrations of oligomers.

Effect of permeability and density difference on convective mixing and storage of CO2 in saline aquifers

The density-driven natural convection is believed to have a positive impact on CO2 storage in saline aquifers. In this regard, studying the parameters that influence the onset of convection is crucial for determining the optimal storage location. Here, we conducted a numerical analysis to investigate how the permeability of the porous medium and the density difference between the brine and CO2-brine mixture affect the mixing efficiency, speed, and development of convective fingers. Results showed that greater permeability and density difference result in a faster onset of convection; hence, fluid velocity and mixing efficiency will increase. Moreover, considering CO2 dissolution based solely on Rayleigh number is not entirely accurate. In addition, if there are different permeability and density difference values, even with a constant Rayleigh number, the mixing of CO2 and brine would not be the same.

Role of Underground Carbon Storage to Assist Reaching Net Zero by 2050: Perspectives on Petroleum Reservoirs

This article focuses on the critical role of sedimentary basins in underground carbon storage. Focusing on both depleted petroleum reservoirs, as well as sedimentary reservoirs in the field’s petroleum stratigraphy (associated sedimentary reservoirs), it highlights the importance of complete CO2 storage in saline aquifers associated with petroleum reservoirs. This paper provides a novel approach to the understanding of underground carbon sequestration (UCS) by combining the examination of target reservoirs and regulation of activities in these reservoirs. By combining this consideration of physical characteristics with legal issues arising from the regulation of UCS, and their application to emerging Australian UCS projects, this novel evaluation of the progress in UCS provides a unique insight into Australian existing and planned UCS Projects. The findings of the research indicate that depleted petroleum reservoirs are more suited to enhanced oil recovery techniques, while associated sandstone reservoirs (saline aquifers) of the same formation are more suited to UCS. The suitability of a reservoir should be considered in the regulation of UCS activities. The example of Australia presented in this paper demonstrates the difficulties in such regulation.

CO2-enhanced oil recovery with CO2 utilization and storage: Progress and practical applications in China

CO2 capture, utilization, and storage (CCUS) is a strategic emerging technology that has undergone rapid development in recent years. CO2-Enhanced oil recovery with CO2 utilization and storage (CCUS-EOR) is currently the most practicable large-scale carbon reduction technology and has become a key tool for large-scale applications of CCUS. In the inceptive period, CCUS-EOR was targeted towards flooding, but has since been extensively adopted for industrialization. At present, CCUS-EOR is being developed for synergistic flooding and storage, and is expected to gradually transition to utilization in geological storage for supporting large-scale carbon reduction to achieve the goal of carbon neutrality. The primary mechanisms controlling CCUS-EOR differ for high-permeability, high-water-cut oil reservoirs; low-permeability oil reservoirs; extra-low permeability oil reservoirs; and tight and shale oil reservoirs. Therefore, identifying the main constraints in the CO2 flooding process and formulating effective development strategies are necessary for maximizing both oil recovery and storage. In the geological storage of CO2, attention must be paid to key factors such as the storage capacity, injectivity, and safety. The storage performance can be enhanced through methods such as synergistic CO2-enhanced water recovery and CO2 storage (CCS-EWR), as well as rapid carbon mineralization in basalt. Globally, CCUS projects have undergone rapid growth, with more than 90 % of operational projects led by or involving oil and gas companies. In China, CCUS-EOR is currently in the early stage of industrial application. The first million-ton CCUS project has recently been completed. China has great potential for CCUS-EOR. An advantage of CCUS-EOR is the early adoption to large-scale applications, while CO2 storage in saline aquifers provides a foundation for promoting large-scale development. In the future, multiple CCUS-EOR clusters are expected to be established in the Bohai Bay Basin, Songliao Basin, Ordos Basin, Yangtze River Delta, and Pearl River Delta regions, which will drive high-quality development of CCUS applications in China. ChineseLibrary Classification Number TE341. Document CodeA.

Prediction of shale wettability using different machine learning techniques for the application of CO2 sequestration

Understanding the behavior of carbon dioxide (CO2) wetting in shale formations is crucial for various applications such as CO2-enhanced oil recovery, CO2 foam hydraulic fracturing, and CO2 storage in saline aquifers and shale formations. However, traditional laboratory methods to determine shale wettability, including contact angle measurements and nuclear magnetic resonance spectroscopy, can be time-consuming and expensive. This study aims to overcome these limitations by utilizing machine learning (ML) techniques to estimate shale wettability based on shale characteristics and experimental conditions.A dataset was collected, encompassing different shale samples under various conditions, including pressure, temperature, and brine salinity, to predict shale wettability. Pearson's correlation coefficient and linear regression analysis were employed to assess the relationship between the contact angle value and other input parameters. ML models, including decision tree, random forests, function networks, and gradient boosting regressor, were utilized for shale wettability prediction.Operating pressure, temperature, rock mineralogy, and total organic content were identified as influential factors on shale wettability. While the linear regression model showed limited accuracy, the ML models, especially random forests, decision tree, gradient boosting regressor, and function networks, effectively predicted the contact angle value with high R2 values. Gradient boosting regressor demonstrated the best performance, achieving R2 values of 0.99 and 0.98 for the training and testing datasets, respectively, with a root mean square error below 5 degrees. Sensitivity analysis revealed the significant impact of pressure on shale wettability, with low pressures resulting in water-wet shale regardless of other shale properties.The study highlights the efficacy of the developed ML models in predicting shale wettability in the context of CO2-water-shale systems, providing a faster and more affordable alternative to complex experimental analyses.

Study Makes Value Proposition for Carbon-Neutral Fuel From Light Tight Oil

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2021-5437, “Carbon-Neutral Fuel From Light Tight Oil: A Value Proposition,” by Christine A. Ehlig-Economides, SPE, University of Houston. The paper has not been peer reviewed. _ Emissions for light tight oil often begin with associated gas. Rather than flare the stranded methane, an option may be to use it to power capture of CO2 from the air using direct air capture (DAC) technologies. This study catalogs global gas/oil ratio (GOR) data to identify currently produced light crude oils that could be rendered carbon-neutral through the DAC mechanism. It then considers operational aspects, including proximity to a suitable location for a DAC unit and proximity to subsurface utilization or storage opportunities, that favor or discourage this approach. Introduction Previous work by the author defined carbon-neutral crude oil (CNCO) as crude oil that has offset the CO2 to be emitted by its combustible products before its arrival at the sale point. Other authors refer to enhanced oil recovery (EOR) using anthropogenic CO2 and including monitoring, verification, and reporting as EOR+. They describe three EOR+ categories: conventional, advanced, and maximum storage. Conventional storage minimizes CO2 use to reduce cost, resulting in net usage of 0.3 t CO2/bbl. Advanced-storage miscible flooding follows current best practices for optimized oil recovery and also may involve some “second-generation” approaches that boost CO2 use, resulting in net usage of 0.6 t CO2/bbl. Maximized storage effectively uses the reservoir pore space for additional CO2 storage without additional oil production and may include removing water, resulting in net usage of 0.9 t CO2/bbl. CO2 Capacity The pore-space requirements for saline aquifer CO2 storage depend on whether primary or secondary storage is envisioned for the short term. Primary storage entails bulk CO2 injection into an aquifer storage volume effectively limited by interference with neighboring injection wells, while secondary storage entails producing the same volume from the reservoir as is injected as CO2. The bulk rock volume required to store CO2 dissolved in brine is approximately 200 times the original coal volume (Fig. 1). Limiting the injection pressure below the fracturing pressure to avoid breaching the caprock, however, further limits the CO2 storage capacity to approximately 6% of the pore space. This makes the multiplier nearly 120 times the original coal volume without CO2 dissolution. Generally, CO2 captured from stationary point sources and stored through multiwell bulk injection in a saline aquifer has a primary storage capacity of approximately 4.2 t CO2/acre-ft without increasing the original aquifer pressure. Three tables in the complete paper list inputs for these estimations and parameters derived from these inputs for cases corresponding to primary and secondary storage without aquifer pressurization. If CO2 injection elevates the aquifer average pressure, this increases the risk of inducing earthquakes and fracturing through the caprock. Using a typical fracture gradient of 0.7 psi/ft, injectivity of 3.23 BOPD/ft/psi could enable elevating the aquifer average pressure to 6,297 psia, which would, in turn, enable increasing the primary storage capacity to 18 t CO2/acre-ft and secondary storage capacity to 135 t CO2/acre-ft, again without CO2 dissolution. It is useful to compare maximized EOR+ with secondary CO2 storage in a saline aquifer. Effectively, maximized storage is like secondary saline aquifer storage in a sealed and trapped reservoir volume. Elevating pressure can increase the storage efficiency in either case, though with associated risks.

Advanced modeling of enhanced CO2 dissolution trapping in saline aquifers

A consistent thermodynamic model based on a combination of the Peng-Robinson equation of state for gas components with an activity model for the aqueous phase is utilized in this study to accurately evaluate the performance of geologic CO2 storage in saline aquifers. To account for thermal effects, the phase enthalpy and conductivity are derived with consideration of CO2 dissolution in brines. Several conceptual numerical setups with variations in parameters and physics are constructed to investigate the enhanced CO2 dissolution in saline aquifers. In addition, a realistic geological structure is considered to evaluate the potential for storing CO2 at the field scale. Our simulation results show that the presence of a capillary transition zone (CTZ) can significantly reduce the onset time and enhance the dissolution rate. The temperature has a crucial effect on the dissolution trapping compared to isothermal assumptions. Thermal conduction and convection suspend the onset of mass convection, while the final mass flux is augmented. Heat conduction smears out the temperature difference between rocks and fluids, thus suppressing thermal fingering. We demonstrate that the dissolution trapping in realistic 3D aquifers can be significantly different from their 2D analogues. The field-scale simulation results show that the dissolution rate increases sharply once the convection dominates the CO2 migration which corresponds to a reduction of residual trapping. Besides, a high-resolution 3D model is required for accurately resolving the enhanced CO2 dissolution in realistic heterogeneous reservoirs. An efficient multi-scale framework for an accurate evaluation of CO2 trapping is proposed for this purpose.

Progress for carbon dioxide geological storage in West Macedonia: A field and laboratory-based survey

Background: It is widely acknowledged that carbon dioxide (CO2), a greenhouse gas, is largely responsible for climatic changes that can lead to warming or cooling in various places. This disturbs natural processes, creating instability and fragility of natural and social ecosystems. To combat climate change, without compromising technology advancements and maintaining production costs at acceptable levels, carbon capture and storage (CCS) technologies can be deployed to advance a non-disruptive energy transition. Capturing CO2 from industrial processes such as thermoelectric power stations, refineries, and cement factories and storing it in geological mediums is becoming a mature technology. Part of the Mesohellenic Basin, situated in Greek territory, is proposed as a potential area for CO2 storage in saline aquifers. This follows work previously done in the StrategyCCUS project, funded by the EU. The work is progressing under the Pilot Strategy, funded by the EU. Methods: The current investigation includes geomechanical and petrophysical methods to characterise sedimentary formations for their potential to hold CO2 underground. Results: Samples were found to have both low porosity and permeability while the corresponding uniaxial strength for the Tsotyli formation was 22 MPa, for Eptechori 35 MPa and Pentalofo 74 MPa. Conclusions: The samples investigated indicate the potential to act as rock caps due to low porosity and permeability, but fluid pressure within the rock should remain within specified limits; otherwise, the rock may easily fracture and result in CO2 leakage or/and deform to allow the flow of CO2. Further investigation is needed to identify reservoir rocks as well more sampling to allow for statistically significant results.

Improvement in CO2 geo-sequestration in saline aquifers by viscosification: From molecular scale to core scale

Carbon dioxide (CO2) storage in the subsurface is a viable approach to mitigate climate change by reducing anthropogenic greenhouse gas emissions. The unfavorable mobility ratio in brine displacement by CO2 would lead to poor sweep efficiency. In this investigation, the efficiency of an engineered CO2 oligomer viscosifier with about twenty repeat units of 1-decene is evaluated in mobility control and sweep efficiency improvement in drainage. We have performed brine displacement experiments in sandstone rock with supercritical CO2. The viscosifier at 1.5 wt% concentration increases the viscosity of supercritical CO2 by 4.8 folds at pressure of 3500 psi and temperature of 194 ˚F. We observe significant delay of CO2 breakthrough time by 2.6 ± 0.1 folds in a large number of experiments by viscosified CO2. The molecule does not have appreciable adsorption on the rock surface. The pressure drop from displacement of neat CO2 by viscosified CO2 at 1 PV injection provides the evidence of low adsorption. Molecular simulations are conducted to investigate adsorption. Low adsorption is a key measure of the effectiveness of the molecule. The results from molecular simulations agree with the experiments. In addition to viscosification, the novelty of the molecule is that there is a significant decrease in the residual brine saturation. Consequently, the residual trapping is also increased. The combination of decrease in residual brine saturation, and mobility control are expected to significantly improve the storage capacity through increase in residual trapping and sweep efficiency in CO2 storage in saline aquifers. As a result, CO2 storage may become more efficient.

Risk evaluation of CO2 leakage through fracture zone in geological storage reservoir

CO2 storage in saline aquifers is an effective way to reduce the emission of CO2 into the atmosphere. The potential leakage problems are the main challenge for CO2 storage projects. However, the quantitative evaluation and analysis of the driving forces for the potential CO2 leakage problems are still lacking. In this paper, a stratified model embedded with a highly-permeable fracture zone was constructed to simulate CO2 leakage in the post-injection period. The acting forces and dimensionless numbers were systematically analyzed, and four stages were defined based on the leakage characteristics. Ultimately, a novel regression model was developed to predict the percentage of secure storage for CO2 at any dimensionless numbers. Results showed four distinct CO2 leakage stages: fast CO2 leakage stage (T1); decreasing CO2 leakage stage (T2); fast water sink stage (T3); and stable countercurrent flow stage (T4). Viscous force, gravity force, and capillary force were the dominant driving forces in turn in the first three stages. A stable countercurrent flow and CO2 leakage were maintained in the last period. In addition, the turning point of the flow pattern was delayed, and Gravity number (Gr) and Bond number (Bo) decreased obviously with the increase of initial pressure gradient. More importantly, most of the leaked CO2 was trapped in riskier forms (i.e. structural and residual trapping), and heavy acidification occurred in the shallow aquifer. The novel regression model showed that the percentage of secure storage could be enhanced by increasing Gr and/or decreasing the Ca. It is suggested that the pressure gradient at the end of injection should be optimized to store more CO2 and decrease the leakage risk simultaneously.

CO2 storage potential assessment of offshore saline aquifers in China

Saline Aquifer CO2 Storage (SACS) has become a vitally important technology for mitigating climate change brought on by anthropogenic and fossil fuel emissions. Application of SACS projects in offshore saline aquifers in China is quite promising, and the CO2 storage technical and economic potential are considerable. However, the storage capacities achieved from different analytical and numerical methods varies a lot from each other since the main factors taken into account are variable.In this paper, different methodologies are applied to conduct the assessment of CO2 storage capacity of offshore saline aquifers including Bohai Bay Basin in northern China, also Beibu Gulf Basin and Yinggehai Basin in southern China. Results show that the storage capacity obtained from European Commission’s method is much less than that determined by the other three methods (i.e., USDOE, CSLF and CO2BLOCK method) since it mainly effected by the area of the saline aquifers. Since both of the CSLF and CO2BLOCK methods take into the account the storage mechanisms such as geological structure storage, residual gas storage and dissolution storage, the results seem more reasonable. In addition, the CO2BLOCK method considers the formation stability during injection as well, which is more in accordance with the reality. In summary, the CO2 storage potential of Bohai Bay Basin, Beibu Gulf Basin, and Yinggehai Basin are 39.98, 53.22, and 13.37 Gt, respectively. This further verifies the great potential of industrial-scale pilot and demonstration CO2 storage projects in offshore deep saline aquifers in China.

Geochemical reaction of compressed CO2 energy storage using saline aquifer

During the use of compressed CO2 storage in saline aquifers, complex geochemical reactions may occur, affecting the petrophysical properties of the reservoir rocks and leading to CO2 depletion. In this paper, the geochemical reaction mechanism of CCES-SA was studied numerically with the Yingcheng Group in the southeast uplift area of the Songliao Basin as the study area. The hydrogeological parameters of the target study area were used as the initial parameters for the numerical simulation study, and the CO2-brine-rock geochemical reaction simulation was carried out using the reaction transport model to study the effects of the 20-year geochemical reaction on the physical properties of reservoir rocks and CO2 consumption through numerical simulation. The following results were obtained by analyzing the numerical simulation results. The long-term geochemical reactions dissolved chlorite and feldspar minerals, etc., and also precipitated carbonates and clay minerals, etc., which were consistent with the actual results. Besides, the dissolution and precipitation of the above minerals did not affect the porosity and permeability of underground aquifers and did not have adverse consequences for extraction. At the end of 20 years of inter-seasonal energy storage, the percentages of CO2 captured in gas, aqueous phase and minerals were 27%, 65% and 8%, respectively. During storage, it was recommended to inject CO2 appropriately during closure to maintain gas phase CO2 content and pressure. During the production process, the acidified formation fluid came into contact with the inner pipe, increased the risk of wellbore corrosion. When selected materials for wellbore materials, it was recommended to choose corrosion-resistant pipes. What was studied in this paper could provide a theoretical reference for underground energy storage projects involving fluid-rock interactions.

Simultaneous Prediction of Equilibrium, Interfacial, and Transport Properties of CO2-Brine Systems Using Molecular Dynamics Simulation: Applications to CO2 Storage

This study aims to provide accurate simultaneous predictions of crucial properties affecting CO2 storage in saline aquifers with deep microstructural insights using comprehensive molecular dynamics (MD) simulations under actual operating conditions ranges. We investigated the effects of pressure, temperature, and salinity on mutual solubility, interfacial tension (IFT), density, and viscosity of a CO2-brine system over the temperature range of 323.15–393.15 K, pressures up to 30 MPa, and salinity range of 0.98–2.97 mol/kg. Brine was resembled by employing different brine systems like actual reservoirs, including mixed electrolyte solutions containing monovalent and divalent ions. MD model configurations and force fields were validated by experimental data of a CO2-water/NaCl aqueous solution. The maximum average absolute deviations for the solubility, density, and IFT were 5.50, 6.95, and 7.136%, respectively. The simulation results indicated that mutual solubilities of CO2 and water in the CO2-NaCl + KCl solution system are higher than those of CO2-NaCl + CaCl2, while for IFT, the opposite trend is observed. Unlike pressure, salt concentration variations result in considerable density and viscosity changes for all systems. The maximum density and viscosity values are obtained for the brine-containing divalent cations. This study gives insight into the storage process and relates the microstructure effects to solubility, IFT, and viscosity of CO2-brine systems using a single MD model.

A Review of Phase Behavior Mechanisms of CO2 EOR and Storage in Subsurface Formations

The emissions of CO2 have been recognized as the main cause of climate change. As an important strategy being used to reduce the CO2 concentration in the atmosphere, carbon capture, utilization and storage (CCUS) has attracted significant attention in recent years. Geological formations, including depleted oil and gas reservoirs and saline aquifers, are popular CO2 storage options. During the process of CO2 storage in subsurface formations, the interactions between CO2 and formation fluids must be considered as they could greatly affect the CO2 trapping mechanisms and CO2 storage capacity. In this paper, we give a brief review of the phase behavior mechanisms associated with CO2 storage in subsurface formations. Two different CO2-storage strategies are considered in this paper: CO2 storage in saline aquifers and CO2 storage in oil reservoirs. Multiphase equilibria, including two-phase, three-phase, and four-phase equilibria, can be observed during CO2 injection into underground formations. Both the experimental and modeling studies on the related phase behavior mechanisms are included in this Review. We also introduce some recently developed robust algorithms for the multiphase equilibria calculations, which could be essential for the design of the CO2 storage process and prediction of CO2 storage capacity.

Pressure-derived storage efficiency for open saline aquifer CO2 storage

Pressure-derived storage efficiency for open saline aquifer CO2 storage

Pore scale modeling and evaluation of clogging behavior of salt crystal aggregates in CO2-rich phase during carbon storage

The optimal CO2 storage operation requires high permeability in the near-well region in order to keep it safe and cost-efficient. Nucleation and growth of salt crystals driven by the evaporation of formation water into under-saturated (dry) super-critical CO2 streams result in the changes in porosity and permeability of the near well-bore area. Permeability reduction is one of the main reasons for injectivity losses in the context of CO2 storage in saline aquifers. According to recent studies, during CO2 storage, salt crystals grow in two different forms: 1) single, large crystals in the aqueous phase, and 2) aggregates of micro-meter size salt crystals in the CO2-rich vapor phase. All previous numerical studies at pore-scale have addressed the formation of single, large crystals in the aqueous phase. In this work we have developed a 3D pore-scale reactive transport solver based on a D3Q19 advection-diffusion Lattice-Boltzmann model. The model takes for the first time salt nucleation into consideration via a new probabilistic approach to simulate the formation of micro-meter size salt crystal aggregates in the CO2-rich phase and their effect on changes in pore morphology and permeability. Comparing the results of porosity-permeability relations with some of the well-known clogging models, confirms the need for a new clogging model to capture the permeability reduction caused by salt aggregates.

Evaluating numerical simulation errors of CO[formula omitted]-brine flow with capillary heterogeneity using a 1D semi-analytical solution

Modeling CO2-brine flow related to CO2 storage in saline aquifers involves intense numerical simulations. One of the important processes associated with these flows, allowing for safe long term storage of CO2, is residual trapping. For accurate modeling of trapping, capillary heterogeneity should be incorporated in the models. However, there have been some reports of increased numerical simulation errors associated with these models and yet no systematic study of their accuracy has been carried out.We compare results of two numerical simulators to a semi-analytical solution of 1D two-phase immiscible steady state flow with capillary heterogeneity. Simulation errors are calculated for a wide range of different flow rates, fluid fractions, capillary pressure curves and heterogeneities. Results show that capillary pressure and saturation errors increase with smaller dimensionless capillary number and reach large values of 25−50% for many cases. It is shown that the errors are related to capillary heterogeneity and therefore increase also with larger variance of log permeability. Finally, a new approach for predicting numerical errors without employing an analytical solution is proposed, i.e., the error indicator analysis.

Numerical modelling of long-term CO2 storage mechanisms in saline aquifers using the Sleipner benchmark dataset

We present numerical modelling of long-term CO2 storage in saline aquifers using field dataset in the Sleipner carbon capture and storage project in offshore Norway. A compositional reservoir simulation model was constructed for an entire section of the reservoir whose thickness is approximately 200 m. We used a fine grid system with a thickness of down to 0.2 m to capture thin intraformational mudrock barriers which can play an important role in the upward migration of injected CO2 as observed in 4D seismic datasets. The threshold capillary pressure and vertical permeability of these mudrock barriers were tuned to have nine separated CO2 plumes below the mudrock layers as observed in the corresponding seismic data. The mismatches in the CO2 plume between our simulation result and 4D seismic observation suggested further model tuning. The simulation was extended without further CO2 injection. During CO2 injection, the dominant storage mechanism was structural trapping, which was influenced by the properties of intraformational mudrock barriers. After the end of CO2 injection, the amount of residual gas trapping started to increase. The significant change in the storage mechanisms occurred during a period of 20 years after shut-in. At 100 years and onward, solubility trapping took effect with the decrease of residually trapped CO2. Mass diffusion of CO2 in formation brine controlled the degree of the invasion of CO2 into the cap rock over 1000 years of our simulation limit.

Engineering design of CO2 storage in saline aquifers and in depleted hydrocarbon reservoirs: similarities and differences

The types of geological structures suitable for CO2 storage are saline aquifers (SA) and depleted hydrocarbon reservoirs (DHR). It is well-known that a direct comparison is often somewhat misleading; the preferences depend on many factors, including availability, logistical and economic concerns. However, advantages and disadvantages in terms of various engineering aspects are often compared. We summarize the state-of-the-art of knowledge on the use of SAs and DHRs. Physical processes involved, analytical and numerical approaches for capacity and injectivity estimations, containment, wellbore and near-wellbore challenges and logistical options are discussed for both options. Comparisons are made considering engineering design for the onshore and offshore cases together with the preliminary economics.

Storage of Carbon Dioxide in Saline Aquifers: Physicochemical Processes, Key Constraints, and Scale-Up Potential.

CO2 storage in saline aquifers offers a realistic means of achieving globally significant reductions in greenhouse gas emissions at the scale of billions of tonnes per year. We review insights into the processes involved using well-documented industrial-scale projects, supported by a range of laboratory analyses, field studies, and flow simulations. The main topics we address are (a) the significant physicochemical processes, (b) the factors limiting CO2 storage capacity, and (c) the requirements for global scale-up.Although CO2 capture and storage (CCS) technology can be considered mature and proven, it requires significant and rapid scale-up to meet the objectives of the Paris Climate Agreement. The projected growth in the number of CO2 injection wells required is significantly lower than the historic petroleum industry drill rates, indicating that decarbonization via CCS is a highly credible and affordable ambition for modern human society. Several technology developments are needed to reduce deployment costs and to stimulate widespread adoption of this technology, and these should focus on demonstration of long-term retention and safety of CO2 storage and development of smart ways of handling injection wells and pressure, cost-effective monitoring solutions, and deployment of CCS hubs with associated infrastructure.