Assessment Of CO2 Storage Capacity Research Articles

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.

3D reservoir simulation of CO 2 injection in a deep saline aquifer of the Lower Paleozoic Potsdam Sandstone of the St Lawrence Platform, Gentilly Block, Quebec

Increasing demand in carbon dioxide storage volumes to reduce greenhouse gas emissions to net zero by 2050 implies assessment of CO 2 storage capacity, including deep saline aquifers, even in tight sandstone reservoirs. 3D reservoir simulations of supercritical CO 2 injection were carried out in the Lower Paleozoic Potsdam Sandstone of the St Lawrence Platform (Gentilly Block), Quebec to predict safe CO 2 injection rates, evaluate reservoir pressure build-up in the presence of sealing and permeable faults, and estimate the gas injection cumulative. 3D one-way coupled reservoir–geomechanical modelling helped to analyse the interaction between reservoir pressure build-up and changes in in situ stresses, and estimate the risk of top and bottom seal failure and fault shear-slip reactivation. It is shown that a safe CO 2 injection rate per well for 20 years of continuous injection is estimated to range from 0.7 kg s −1 (22.1 kt a −1 ) to 10 kg s −1 (315.4 kt a −1 ) depending on the porosity and permeability of the Potsdam Sandstone varying from core-derived matrix values to ‘fracture-enhanced’ values. The corresponding injection CO 2 cumulative for 20 years ranges from 432.2 to 6013.5 kt per well. The implementation of a multiple-well injection plan will help to increase the injection CO 2 cumulative, given the considerable thickness and basin-scale dimensions of the Potsdam reservoir (3440 km 3 ).

Assessment and uncertainty quantification of onshore geological CO2 storage capacity in China

We provide a probabilistic assessment of CO2 storage capacity in major sedimentary basins in China. Our approach embeds constraints associated with the increase of reservoir pore pressure due to injection of CO2 in the presence of resident brine. Pressure build-up must be limited to avoid fault reactivation, caprock failure, and possible leakage, resulting in more conservative estimates of CO2 storage capacity as compared to volumetric estimates.We rely on a numerical Monte Carlo framework considering uncertainty in the values of reservoir size and major geological formation attributes (i.e., absolute permeability, porosity, and reservoir compressibility). Our work shows that 10 major basins can potentially store, on average, 1350 Gt of CO2 during the next 30 years (lower and upper quartiles being 1100 and 1700 Gt of CO2, respectively). This far exceeds the likely amount (up to 175 Gt of CO2) required to be stored by 2050. Our analysis also suggests that 6 basins (located close to the largest emission areas) can store about 93 Gt (on average) of CO2 during the next 30 years. Underground carbon storage in China, coupled with other possible solutions, could meet the aims of the Announced Pledges Scenario (International Energy Agency) to mitigate global warming by 2060.We also perform a global sensitivity analysis to determine how our predictions of storage capacity may be affected by uncertainties in the simulation model input parameters. Moment-based global sensitivity metrics suggest that geological formation attributes are major sources of uncertainty, significantly affecting model outputs and the associated uncertainty.

An integrated model for carbon geo-sequestration considering gas leakage

Carbon geo-sequestration is a promising method for mitigating global warming and climate change. Depleted shale gas reservoirs with high adsorption capacities, excellent sealing properties, and complete infrastructure are potential sites for CO2 storage. However, hydraulic fracturing and extensive CO2 injection can result in fault reactivation, leading to CO2 migration and an increased risk of environmental contamination. Given this problem, a partially permeable boundary is introduced to characterize permeable faults. Herein, a novel methodology based on rate transient analysis that considers CO2 adsorption, diffusion, and leakage is proposed for evaluating the CO2 storage capacity of depleted shale gas reservoirs. The analytical solution for a multiple fractured horizontal well with finite conductivity is derived from the principle of potential superposition, Laplace transform, and correction functions. Subsequently, according to the analytical solutions, a rapid and robust CO2 storage capacity assessment technique is established. Using field data of the Marcellus shale, a sensitivity analysis is performed to analyze the effects of the reservoir and well parameters on the injection performance, carbon storage potential, and CO2 leakage risk. The results indicate that the proposed model is consistent with previously reported semi-analytical models and numerical simulations. The injection rate and cumulative leakage ratio increase with the leakage ratio, resulting in gas migration and an increased risk of leakage. Reservoirs with large drainage radii, high Langmuir volumes, and small Langmuir pressures are suitable for carbon sequestration, significantly increasing the adsorption capacity and reducing the leakage risk. In this study, a novel method is used to calculate the analytical solution for multiple fractured horizontal wells, which allows a rapid and practical CO2 geo-sequestration capacity assessment for CO2 storage projects.

On CO2 sequestration in concrete aggregate via carbonation: simulation and experimental verification

The paper deals with the assessment of CO2 storage capacity in cement concrete using reactive transport modelling of the accelerated carbonation, i.e. 15 Vol % and experiments. To meet the most realistic geometry of concrete aggregates, the numerical solution is achieved using a homogeneous concrete without aggregates and two-phase concrete including aggregates. We utilise the reactive transport model to estimate molar concentration of cement components and porosity distribution during CO2 carbonation. The model also computes the hydration process before and during carbonation. The numerical solutions are obtained from an extremely nonlinear transient system of Partial Differential Equations (PDEs). The experiments of CO2 carbonation have been carried out using coarse concrete aggregates after 6 months of curing in water. Based on Thermal Gravimetric Analysis (TGA), CO2 uptake during carbonation is determined in weight percent. The numerical simulations fairly agree with the experiments. Highlights CO2 sequestration calculation via chemical reactions Single-Phase & 2-phase numerical concrete aggregate Accelerated carbonation modelling & experiments.

Directional Hydraulic Characteristics of Reservoir Rocks for CO2 Geological Storage in the Pohang Basin, Southeast Korea

This study conducted core sampling of an offshore borehole for geological reservoir characterization of a potential CO2 storage site in southeast Korea. From this, two promising geological formations at ~739 and ~779 m were identified as prospective CO2 storage reservoirs. Injection efficiency and CO2 migration were evaluated based on directional measurements of permeabilities from core plugs. The directional transport properties were determined using both a portable probe permeameter and a pressure cell capable of applying different in situ confining pressures. Both steady state and unsteady state measurements were used to determine permeability—the method selected according to the expected permeability range of the specific sample. This expected range was based on rapid screening measurements acquired using a portable probe permeameter (PPP). Anticipated performance of the prototypical CO2 injection site was evaluated based on flow modeling of the CO2 plume migration pathway including CO2 transport through the overlying formations based on the measured directional hydraulic properties. These analyses revealed that the injection efficiency at a depth of 739 m was double that at 779 m. These correlations among and distributions of the directional permeabilities of the potential CO2 geological storage site can be utilized for the assessment of CO2 storage capacity, injectivity, and leakage risk.

How large is our CO2 storage capacity assessment error? Analyzing the magnitude of error in the effective capacity calculation propagated from uncertainties in the thermophysical conditions in the aquifer, the case of the Israeli Jurassic saline aquifer

CO2 storage capacity assessment at a regional or country-size scale is one of the first tools for screening and ranking potential aquifers for deep geological storage. The estimated mass of the stored CO2 depends on the density of the supercritical CO2, which in turn is controlled by the aquifer hydrostatic pressure and temperature conditions. In this paper, we examine the magnitude of error in CO2 density and total storage capacity arising from uncertainties in subsurface temperature and pressure, and in particular from uncertainties in the surface temperature, geothermal gradient, depth of the piezometric-surface and the density of the formation water, that could propagate into the CO2 density and the total storage capacity calculations. Using the Israeli saline Jurassic aquifer as a case study, we establish the spatial distributions of the above temperature and hydrostatic pressure components and evaluate the errors using 'Monte Carlo' and 'one-factor-at-a-time' analyses. Our study shows that the depth of the piezometric-surface and the geothermal gradient have the strongest effect on the CO2 density and on the depth of the transition to supercritical CO2, whereas the influence of the surface temperature and the density of the formation water is rather small. As a side result of our study, we are showing that using average values or literature-derived values for the examined parameters, in the case of the Jurassic aquifer, over estimates the total storage capacity by 10% relative to the case where the spatial distribution of those parameters is used. While the analysis of the storage capacity was demonstrated here for the Jurassic saline aquifer in Israel, the conclusions concerning the effect of hydrostatic pressure and temperature uncertainties on the CO2 density and on the depth of the transition to supercritical CO2 are general and are especially important for relatively shallow or relatively thick aquifers in which the change in CO2 density with depth is large.

Evaluation of Practicable Subsurface CO2 Storage Capacity and Potential CO2 Transportation Networks, Onshore North America

Carbon Capture, Utilization and Storage (CCUS) is considered to be a potentially important technology for reducing the amount of carbon dioxide (CO2) released into the atmosphere from anthropogenic emission sources. With recent progress on capture technologies, attention is increasingly turning to the identification of key challenges associated with CO2 transportation and storage at the scale being considered for the CCUS industry. Decades of oil and gas production have provided experience in application of technologies required for CO2 transportation and storage, but the challenges unique to CO2 storage still need to be evaluated. This paper describes a scoping-level assessment of practicable subsurface geologic CO2 storage capacity and a potential Carbon Capture, Utilization, and Storage (CCUS) industry in the US and Canada, leveraging publically available data/information, publications, and methodologies. Likely subsurface CO2 storage sites and distribution of storage capacity relative to major anthropogenic sources are first characterized using a probabilistic methodology previously developed by the US Geologic Survey (USGS), which was modified to account for several practical factors affecting storage capacity. Major factors considered include 1) subsurface lateral accessibility restrictions imposed by faulting and/or stratigraphic pinch-outs, 2) the proportion of net storage-quality sand comprised of thin sands unlikely to be good injection candidates, 3) surface access restrictions, and 4) dynamic injectivity/storage efficiency considerations. Potential regional CCUS networks are then modeled using a transportation cost framework to map CO2 sources to storage sinks. The USGS assessment and most other existing assessments of storage capacity are based on the premise that all engineering approaches and hardware required to achieve the highest possible storage efficiency would be employed, and that injection rate and timeframe are not issues, with perhaps hundreds to thousands of years of injection permitted to achieve full storage efficiency. We explore the impact of dynamic injectivity considerations on practical storage efficiency by using reservoir simulation models to account for subsurface pressure limitations and the impact of permeability differences and lateral accessibility on CO2 injectability, and then use the results of the modeling to derive a debiting function that reduces the range of static storage capacity estimated by the USGS. Debiting functions accounting for lateral accessibility, thin sands, and surface access restrictions were also applied to obtain practicable storage estimates. Key conclusions from the study include: 1) Although the modified storage capacity estimates are lower than previously published estimates, the estimated subsurface storage capacity in the US onshore is sufficient to sustain a large-scale CO2 storage industry. We estimate that about 500 Gt of potential US subsurface storage capacity is potentially available (excluding federal offshore capacity) even after accounting for dynamic injectibility considerations, thin sands, surface and lateral access issues. Dynamic injectability factors had the largest impact on the reduction in estimated storage capacity. 2) Significant geographic misalignment exists between current high-volume CO2 emission sources and storage availability in North America. This could affect evolution of CO2 transportation networks with time. Detailed site-specific assessments of subsurface storage capacity are required for site selection and actual project implementation. These efforts could change some of the conclusions of this study. In particular, consideration of legacy wells and geomechanical factors such as induced seismicity, ground surface deformation, and fault activation may further reduce storage capacity relative to the estimates presented here. Nevertheless, the methodology described in this paper may be useful for initial assessment of CO2 storage capacity and matching of CO2 emission sources to storage sinks in geographic locations other than those considered in this study.

Assessment of CO2 storage capacity based on sparse data: Skade Formation

Large North Sea aquifers of high quality are the likely major target for 12 Gt of European CO2 emissions that should be stored in the subsurface by 2050. This involves an upscaling of the present combined injection rate from all European projects, which requires careful examination of the storage feasibility. Many aquifers are closed or semi-closed, with storage capacity mainly constrained by consideration of caprock failure criteria. Because the induced overpressure can propagate to sensitive regions far from the injector, the risk of caprock failure must be examined in terms of large volumes and for long times. This poses challenges with respect to fluid-flow simulation in the presence of highly uncertain aquifer properties. In this work, experts on geology, geophysics, geomechanics and simulation technique collaborate to optimize the use of existing data in an efficient simulation framework. The workflow is applied to the large North Sea Skade Formation, with potential for secondary storage and pressure dissipation in the overlying Utsira Formation. Injection at three locations in Skade gives an overall practical capacity of 1–6 Gt CO2 injected over a 50-year period, depending on the reservoir permeability and compressibility. The capacity is limited by local pressure buildup around wells for the lowest estimated reservoir permeability, and otherwise by regional pressure buildup in shallow zones far from the injection sites. Local deformation of clay due to viscoelastoplastic effects do not have an impact on leakage from the aquifer, but these effects may modify the properties of clay layers within the aquifer, which reduces the risk of lateral compartmentalization. Uplift of the seafloor does not impose constraints on the capacity beyond those set by pressure buildup.

Application of petrophysical shale gas model for CO2 storage capacity assessment of coals

Carbon dioxide storage in unmineable coal seams is a potential solution for the reduction of GHG emissions. For the purpose of storage capacity estimations various static and dynamic models are applied and in this study a simple petrophysical model, originally designed for shale gas reservoirs, has been used. This model comprises of volumetric (free gas) and surface (adsorbed gas) component. Important input data for the model are Langmuir constants and other reservoirs parameters such as water saturation, porosity and rock density. Sorption isotherms on two distinct coals from the Upper Silesia Coal Basin were measured and calculated Langmuir constants with typical reservoir parameters were implemented into the model. It occurred that coal with higher ash content and higher sorption capacity for methane had a lower carbon dioxide sorption capacity. This was reflected in the overall carbon storage capacity which for the two coals varied from 31 m3/t to approximately 42 m3/t of coal at the storage pressure of 5.5-6 MPa where the majority of stored gas is the surface component (sorbed gas).

CO2 Trapping State in Saline Aquifers and its Implications for Site-scale Storage Capacity Assessment

Final trapping state of CO2 in the formation water is key to site selection and long-term safety for commercial scale CO2 geological storage projects. CO2 trapping mechanisms in deep saline aquifers and contribution percentages of different trapping states are reviewed. CO2 will be trapped in free gas state, soluble state and mineral state ultimately once being injected and mineral state can only be effective on the timeframe of tens of thousands of years. For pilot and commercial scale CO2 sequestration projects, site scale CO2 storage capacity assessment with timeframe of a hundred to a thousand year is practical and CO2 trapped in mineral state can be ignored. Assessing methods for CO2 stored in free gas state and soluble state are proposed in the paper based on pH changes, carbon-13 and oxygen -18 isotope exchanges between formation water and injected CO2. Using the suggested methods and water chemistry and isotopic data from experiments and field test for Neogene Guantao and Minghuazhen formations, CO2 stored in soluble state are calculated to be 12.5 g/kgw and 0.22 g/kgw while CO2 stored in free gas state takes 23∼36% of the effective pore volume.

Preliminary geochemical modeling of water–rock–gas interactions controlling CO2 storage in the Badenian Aquifer within Czech Part of Vienna Basin

AbstractPrediction of hydrogeochemical effects of geological CO2sequestration is crucial for planning an industrial or even experimental scale injection of carbon dioxide gas into geological formations. This paper presents a preliminary study of the suitability of saline aquifer associated with a depleted oil field in Czech Part of Vienna Basin, as potential greenhouse gas repository. Two steps of modeling enabled prediction of immediate changes in the aquifer and caprocks impacted by the first stage of CO2injection and the assessment of long-term effects of sequestration. Hydrochemical modeling and experimental tests of rock–water–gas interactions allowed for evaluation of trapping mechanisms and assessment of CO2storage capacity of the formations. In the analyzed aquifer, CO2gas may be locked in mineral form in dolomite and dawsonite, and the calculated trapping capacity reaches 13.22 kgCO2/m3. For the caprock, the only mineral able to trap CO2is dolomite, and trapping capacity equals to 5.07 kgCO2/m3.

The effect of providing details to the model of a geological structure on the assessment of CO₂ storage capacity

Massive emissions of CO2 into the atmosphere are the most direct reason causing global warming and climate change, so more and more countries are starting to focus on carbon abatement technologies. In recent years, the method GCS (Geological Carbon Storage), injecting the CO2 in a supercritical state underground for storage, is considered the most effective way to reduce greenhouse gas emissions. Saline aquifers are given special attention because of its huge amount of storage and, therefore, a deep saline aquifer is the best choice for the storage of CO2. Exemplified by the well-explored Konary structure in the Polish Lowlands, results of assessments of CO2 storage capacity are compared for three cases: (1) a simplified formula based on averaged geological and reservoir parameters and (2) a model of the structure based on averaged geological and reservoir parameters (homogeneous model) and (3) a model of the structure with more detailed geological data (including those on clay interbeds in the sandstone series of the reservoir horizon – heterogeneous model). This allows the estimation of how providing of details of geological and reservoir data, introduced into the model, can affect the ability of CO2 migration within a reservoir horizon intended for CO2 storage, and, consequently, also obtain a more accurate assessment of the capacity that the structure is capable of attaining.

Geochemical responses of a saline aquifer to CO2 injection: experimental study on Guantao formation of Bohai Bay Basin, East China

AbstractGeochemical responses of saline aquifers toward large quantities of CO2 injection are important to the monitoring and safety assessment of CO2 storage. Detailed studies on water‐rock‐CO2 interactions of non‐marine saline aquifers through three batch‐reaction experiments were carried out under simulated reservoir conditions (T = 100°C, P = 10 MPa). pH decreased by 1∼2 and TDS increased by 268 mg/L ∼561 mg/L. Water type evolved from original Cl·SO4‐Na to HCO3Cl·SO4‐Na with a water/rock ratio of 3:1. Chemical components of HCO3, Ca, Mg and K and trace elements of Al, Cr, Mn, Ni and Zn showed a significant increase post CO2 injection. Heavy metals including Cr, Mn, Ni, and Zn in the post‐reaction water exceeded drinking water standards, indicating potential pollution to shallow fresh aquifers by brine/CO2 leakage. K‐feldspar and albite were variably dissolved and kaolinite, chlorite, and Fe‐bearing minerals of pyrite and hematite were newly formed, confirmed by suspended materials in the post‐reaction water, red sediments on the bottom of the reactor, and mineral saturation indexes. δ2HH2O shift was observed and discussed, which was not reported in previous water‐rock‐CO2 interactions studies. One possible reason is geochemical processes of new clay minerals formation under low temperature causing water consumption and δ2HH2O enriched in the residual water. The CO2 saturation and fraction of DIC from CO2 dissolution were calculated to be 23%–36% and 33%–49% under experimental conditions and it is suggested that they can be used for CO2 storage capacity assessment.

Assessment of CO2 storage capacity and injectivity in saline aquifers – comparison of results from numerical flow simulations, analytical and generic models

Methodologies for the basin-scale evaluation of industrial-scale CO2 geological storage in saline aquifers can include the use of analytical tools, generic reservoir simulations, as well as basin-specific flow modelling studies. The selection of appropriate tools is dependent on the scale of investigation. Comparison of the results from these methods for the assessment of basin-scale CO2 geological storage in the Gippsland and Otway basins in Australia suggests that, at this scale, a combination of analytical tools in the form of equations for calculating injection pressure, radius of impact and storage capacity with generic numerical simulations may provide useful first-order predictions for storage capacity and injectivity. However, the development of multiple resources (petroleum, groundwater, coal) in the Gippsland Basin and regional compartmentalisation in the Otway Basin necessitates an additional, coarsely discretised basin-scale numerical model.

CO2 Storage Capacity Assessment of Deep Saline Aquifers in the Mozambique Basin

Abstract This study is the first of its kind that made an assessment of theoretical storage capacity within the deep saline aquifers in the Mozambique Basin. An integrated approach that involved geographic information systems analysis and field data assessment was adopted to estimate the storage capacity. Geological characterization was conducted based on available geological cross-sections supported by well stratigraphy data and data from well-logs. Four separate saline aquifers in the depth ranges of 800 m to 3,500 m below surface were recognized in the basin, each having its own sealing shale layers. The theoretical low- and high-end CO 2 storage capacity for the saline rock formations were estimated using volumetric approach. The integrated approach that involved use of GIS tools and field data has resulted in more robust estimates which reduced the spatial uncertainty and thus constrained CO 2 storage capacity estimations. It also avoided the unrealistic extrapolation throughout the basin, while promoting a proper accounting for the possibility to store CO 2 in multiple overlaying formations. We believe that the digital storage atlas developed should provide a basis for further work to reduce the uncertainty in the estimates and also provide support to policy makers on future planning of CCS projects in the country.

Assessment of CO2 storage capacity in southern Israel

This paper presents the first basin-scale capacity assessment of geological long-term CO2 storage in the subsurface sedimentary section of southern Israel. Based on the current carbon dioxide emissions of 75Mt per year and on the present growth rate, the total accumulated emissions in Israel between 2025 and 2075 are predicted to exceed 7Gt. In light of the Israeli government's decision to ratify the Kyoto Protocol and to undertake specific actions to reduce emissions of greenhouse gases, our aim was to map suitable geological storage site(s) within the deep saline formations of southern Israel. We describe here the storage capacity of the Precambrian to Early Cretaceous section, which extends vertically from the crystalline basement up to the country's main freshwater aquifer. The study area examined is sparsely populated and is not too far from major CO2 point sources.Using geological data from 180 boreholes, we mapped three reservoir-quality units, each with its own top sealing layers. The water salinity (TDS units) in the three aquifers is generally above 3000mg/L and in places reaches 210,000mg/L. Capacity calculations were based on the USDOE methodology, using an effective storage capacity coefficient of 2%.We concluded that the two lowermost saline aquifers in southern Israel have sufficient CO2 storage capacity to cover country's needs for several decades without endangering shallower fresh water aquifers (located 500–1000m above the saline aquifers). Considering only the optimal depth range of 800–2500m, the Jurassic aquifer has an effective storage potential of 4.4Gt, and the deep porous units of Cambrian to Triassic age have an effective storage potential of 1.8Gt. Additional 8.6Gt can be stored at depths greater than 2500m. Altogether, our calculations indicate that deep saline formations in southern Israel alone (about 40% of the country) can store up to 15Gt of CO2, which is about twice as much as the country's needs for the next 50 years.

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

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

CO2 storage capacity assessment of deep saline aquifers in the Subei Basin, East China

Geological storage of carbon dioxide (CO2) is one of the most critical technologies in reducing anthropogenic and fossil fuel emissions to the atmosphere. The most critical scientific problem has been the selection of storage site for long-term safety, as well as reliable and reasonable estimation of CO2 storage capacity. This paper analyzed the stability effect factors in identifying the most suitable reservoir-seal assemblages in the Subei Basin in China. In this area, the Lower Yancheng Formation and the Upper Sanduo Formation were selected accurately based on analysis of their geomorphological and geological characteristics. Considering simultaneously the different tectonic units, cap-rock conditions, hydrodynamic conditions, and other factors, these formations could function as optimal reservoirs. The storage capacity in the aquifer layers hosted by these formations was estimated. The results showed that, on average, the storage capacity of the Lower Yancheng Formation is approximately 21.788×108t, whereas that of the Upper Sanduo Formation is approximately 45.866×108t. For the first-order tectonic units, the total storage capacity of the aforementioned two reservoir formations in the Yanfu Depression and the Dongtai Depression reaches 11.01×108 and 56.644×108t, respectively, at the basin scale.

Assessment of CO2 storage capacity in oil reservoirs associated with large lateral/underlying aquifers: Case studies from China

CO2 injection into oil and gas reservoirs associated with large aquifers takes advantages of lower geological leakage risk associated with oil and gas traps, and large storage capacity of their connected aquifers. The storage capacity in such combined reservoirs can be assessed by a material balance method which considers different trapping states of CO2 in oil reservoirs and aquifers. Case studies of five oil reservoirs selected from Shengli and Jiangsu oilfields in China are conducted and the results show that CO2 storage capacity can be greatly increased if the lateral and underlying aquifers are included. Oil and water displacement and CO2 dissolution in remaining oil are the main forms of CO2 trapping in oil reservoirs, while CO2 gas trapping and dissolution in saline water are the main mechanisms for CO2 storage in associated aquifers. CO2 injection into combined reservoirs can be a favorable option for the oil industry in the near future, and the potentials of CO2 EOR and storage deserve further detailed studies.