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1.
Numerical models are essential tools in fully understanding the fate of injected CO2 for commercial-scale sequestration projects and should be included in the life cycle of a project. Common practice involves modeling the behavior of CO2 during and after injection using site-specific reservoir and caprock properties. Little has been done to systematically evaluate and compare the effects of a broad but realistic range of reservoir and caprock properties on potential CO2 leakage through caprocks. This effort requires sampling the physically measurable range of caprock and reservoir properties, and performing numerical simulations of CO2 migration and leakage. In this study, factors affecting CO2 leakage through intact caprocks are identified. Their physical ranges are determined from the literature from various field sites. A quasi-Monte Carlo sampling approach is used such that the full range of caprock and reservoir properties can be evaluated without bias and redundant simulations. For each set of sampled properties, the migration of injected CO2 is simulated for up to 200 years using the water–salt–CO2 operational mode of the STOMP simulator. Preliminary results show that critical factors determining CO2 leakage rate through caprocks are, in decreasing order of significance, the caprock thickness, caprock permeability, reservoir permeability, caprock porosity, and reservoir porosity. This study provides a function for prediction of potential CO2 leakage risk due to permeation of intact caprock and identifies a range of acceptable seal thicknesses and permeability for sequestration projects. The study includes an evaluation of the dependence of CO2 injectivity on reservoir properties.  相似文献   

2.
Geochemical interactions of brine–rock–gas have a significant impact on the stability and integrity of the caprock for long-term CO2 geological storage. Invasion of CO2 into the caprock from the storage reservoir by (1) molecular diffusion of dissolved CO2, (2) CO2-water two-phase flow after capillary breakthrough, and (3) CO2 flow through existing open fractures may alter the mineralogy, porosity, and mechanical strength of the caprock due to the mineral dissolution or precipitation. This determines the self-enhancement or self-sealing efficiency of the caprock. In this paper, two types of caprock, a clay-rich shale and a mudstone, are considered for the modeling analyses of the self-sealing and self-enhancement phenomena. The clay-rich shale taken from the Jianghan Basin of China is used as the base-case model. The results are compared with a mudstone caprock which is compositionally very different than the clay-rich shale. We focus on mineral alterations induced by the invasion of CO2, feedback on medium properties such as porosity, and the self-sealing efficiency of the caprock. A number of sensitivity simulations are performed using the multiphase reactive transport code TOUGHREACT to identify the major minerals that have an impact on the caprock’s self-sealing efficiency. Our model results indicate that under the same hydrogeological conditions, the mudstone is more suitable to be used as a caprock. The sealing distances are barely different in the two types of caprock, both being about 0.6 m far from the interface between the reservoir and caprock. However, the times of occurrence of sealing are considerably different. For the mudstone model, the self-sealing occurs at the beginning of simulation, while for the clay-rich shale model, the porosity begins to decline only after 100 years. At the bottom of the clay-rich shale column, the porosity declines to 0.034, while that of mudstone declines to 0.02. The sensitive minerals in the clay-rich shale model are calcite, magnesite, and smectite-Ca. Anhydrite and illite provide Ca2+ and Mg2+ to the sensitive minerals for their precipitation. The mudstone model simulation is divided into three stages. There are different governing minerals in different stages, and the effect of the reservoir formation water on the alteration of sensitive minerals is significant.  相似文献   

3.
In the context of carbon capture and storage, deep underground injection of CO2 induces the geomechanical changes within and around the injection zone and their impact on CO2 storage security should be evaluated. In this study, we conduct coupled multiphase fluid flow and geomechanical modeling to investigate such geomechanical changes, focusing on probabilistic analysis of injection-induced fracture reactivation (such as shear slip) that could lead to enhanced permeability and CO2 migration across otherwise low-permeability caprock formations. Fracture reactivation in terms of shear slip was analyzed by implicitly considering the fracture orientations generated using the Latin hypercube sampling method, in one case using published fracture statistics from a CO2 storage site. The analysis was conducted by a coupled multiphase fluid flow and geomechanical simulation to first calculate the three-dimensional stress evolution during a hypothetical CO2 injection operation and then evaluate the probability of shear slip considering the statistical fracture distribution and a Coulomb failure analysis. We evaluate the probability of shear slip at different points within the injection zone and in the caprock just above the injection zone and relate this to the potential for opening of new flow paths through the caprock. Our analysis showed that a reverse faulting stress field would be most favorable for avoiding fracture shear reactivation, but site-specific analyses will be required because of strong dependency of the local stress field and fracture orientations.  相似文献   

4.
The CO2 migrated from deeper to shallower layers may change its phase state from supercritical state to gaseous state (called phase transition). This phase transition makes both viscosity and density of CO2 experience a sharp variation, which may induce the CO2 further penetration into shallow layers. This is a critical and dangerous situation for the security of CO2 geological storage. However, the assessment of caprock sealing efficiency with a fully coupled multi-physical model is still missing on this phase transition effect. This study extends our previous fully coupled multi-physical model to include this phase transition effect. The dramatic changes of CO2 viscosity and density are incorporated into the model. The impacts of temperature and pressure on caprock sealing efficiency (expressed by CO2 penetration depth) are then numerically investigated for a caprock layer at the depth of 800 m. The changes of CO2 physical properties with gas partial pressure and formation temperature in the phase transition zone are explored. It is observed that phase transition revises the linear relationship of CO2 penetration depth and time square root as well as penetration depth. The real physical properties of CO2 in the phase transition zone are critical to the safety of CO2 sequestration. Pressure and temperature have different impact mechanisms on the security of CO2 geological storage.  相似文献   

5.
In CO2 geological storage (CGS) context, the evolution of the caprock sealing capacity has received increasing attention, particularly on a geological time span (thousands of years). At this time scale, geochemical reactions may enhance or weaken the caprock quality. It is widely recognized that, for the reservoir, geological heterogeneities affect the concentration and spatial distribution of CO2, and then affect the extent of gas–water–rock interactions, which in turn alters the hydrogeological properties of the reservoir. However, much less attention of these effects has been paid to the caprock. In this study, we presented and applied a novel approach to evaluate the effects of permeability and porosity heterogeneities on the alteration of minerals, the associated evolution of the caprock sealing efficiency and the containment of supercritical CO2 (scCO2) within the caprock. Even though this is a generic study, several conditions and parameters such as pressure, permeability, and mineral composition, were extracted from a caprock layer of the Shiqianfeng Formation in the Ordos Basin demonstration site in China. For the sake of simplification, a 2-dimensional model was designed to represent the caprock domain. We firstly generated an appropriate heterogeneous random field of permeability with the average permeability taken from the uppermost mudstone layer of the Shiqianfeng Formation, and then the heterogeneity in porosity was incorporated using a joint normal distribution method based on the available data. Homogeneous mineral compositions of the reservoir and caprock were used in all simulations. Simulations of three cases were performed, including a homogeneous case, a case with only permeability heterogeneity and a case with both permeability and porosity heterogeneities. The results demonstrate dramatic influences of permeability and porosity heterogeneities on the migration of scCO2 within the caprock, the alteration of minerals, and therefore the evolution of the caprock sealing quality. Specific to the data used in this study, hydrogeological heterogeneities facilitated the overall penetration of scCO2 within the caprock and promoted the alteration of minerals, thereby weakening the caprock sealing efficiency over the simulation time.  相似文献   

6.
This paper studied the CO2-EGR in Altmark natural gas field with numerical simulations. The hydro-mechanical coupled simulations were run using a linked simulator TOUGH2MP-FLAC3D. In order to consider the gas mixing process, EOS7C was implemented in TOUGH2MP. A multi-layered 3D model (4.4 km × 2 km × 1 km) which consists of the whole reservoir, caprock and base rock was generated based on a history-matched PETREL model, originally built by GDF SUEZ E&P Deutschland GmbH for Altmark natural gas field. The model is heterogeneous and discretized into 26,015 grid blocks. In the simulation, 100,000 t CO2 was injected in the reservoir through well S13 within 2 years, while gas was produced from the well S14. Some sensitivity analyses were also carried out. Simulation results show that CO2 tends to migrate toward the production well S14 along a NW–SE fault. It reached the observation wells S1 and S16 after 2 years, but no breakthrough occurred in the production well. After 2 years of CO2 injection, the reservoir pressure increased by 2.5 bar, which is beneficial for gas recovery. The largest uplift (1 mm) occurred at the bottom of the caprock. The deformation was small (elastic) and caprock integrity was not affected. With the injection rate doubled the average pressure increased by 5.3 bar. Even then the CO2 did not reach the production well S14 after 2 years of injection. It could be concluded that the previous flow field was established during the primary gas production history. This former flow field, including CO2 injection/CH4 production rate during CO2-EGR and fault directions and intensity are the most important factors affecting the CO2 transport.  相似文献   

7.
The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO2-EGR (enhanced gas recovery), and CO2-storage. A generic 3D planer model (20,000?×?3,000?×?100?m, consisting of 1,200?m overburden, 100?m caprock, 200?m gas reservoir, and 1,500?m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO2-EGR phase under a balanced injection rate (31,500?tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4?% in the 5-year CO2-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83?% for 5?km distance, instead of 1.2?km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO2-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6?MPa which is determined by the penetration criterion of the caprock.  相似文献   

8.
Carbon dioxide (CO2) sequestration in depleted sandstone hydrocarbon reservoirs could be complicated by a number of geomechanical problems associated with well drilling, completions, and CO2 injection. The initial production of hydrocarbons (gas or oil) and the resulting pressure depletion as well as associated reduction in horizontal stresses (e.g., fracture gradient) narrow the operational drilling mud weight window, which could exacerbate wellbore instabilities while infill drilling. Well completions (casing, liners, etc.) may experience solids flowback to the injector wells when injection is interrupted due to CO2 supply or during required system maintenance. CO2 injection alters the pressure and temperature in the near wellbore region, which could cause fault reactivation or thermal fracturing. In addition, the injection pressure may exceed the maximum sustainable storage pressure, and cause fracturing and fault reactivation within the reservoirs or bounding formations. A systematic approach has been developed for geomechanical assessments for CO2 storage in depleted reservoirs. The approach requires a robust field geomechanical model with its components derived from drilling and production data as well as from wireline logs of historical wells. This approach is described in detail in this paper together with a recent study on a depleted gas field in the North Sea considered for CO2 sequestration. The particular case study shows that there is a limitation on maximum allowable well inclinations, 45° if aligning with the maximum horizontal stress direction and 65° if aligning with the minimum horizontal stress direction, beyond which wellbore failure would become critical while drilling. Evaluation of sanding risks indicates no sand control installations would be needed for injector wells. Fracturing and faulting assessments confirm that the fracturing pressure of caprock is significantly higher than the planned CO2 injection and storage pressures for an ideal case, in which the total field horizontal stresses increase with the reservoir re-pressurization in a manner opposite to their reduction with the reservoir depletion. However, as the most pessimistic case of assuming the total horizontal stresses staying the same over the CO2 injection, faulting could be reactivated on a fault with the least favorable geometry once the reservoir pressure reaches approximately 7.7 MPa. In addition, the initial CO2 injection could lead to a high risk that a fault with a cohesion of less than 5.1 MPa could be activated due to the significant effect of reduced temperature on the field stresses around the injection site.  相似文献   

9.
This paper reports a preliminary investigation of CO2 sequestration and seal integrity at Teapot Dome oil field, Wyoming, USA, with the objective of predicting the potential risk of CO2 leakage along reservoir-bounding faults. CO2 injection into reservoirs creates anomalously high pore pressure at the top of the reservoir that could potentially hydraulically fracture the caprock or trigger slip on reservoir-bounding faults. The Tensleep Formation, a Pennsylvanian age eolian sandstone is evaluated as the target horizon for a pilot CO2 EOR-carbon storage experiment, in a three-way closure trap against a bounding fault, termed the S1 fault. A preliminary geomechanical model of the Tensleep Formation has been developed to evaluate the potential for CO2 injection inducing slip on the S1 fault and thus threatening seal integrity. Uncertainties in the stress tensor and fault geometry have been incorporated into the analysis using Monte Carlo simulation. The authors find that even the most pessimistic risk scenario would require ∼10 MPa of excess pressure to cause the S1 fault to reactivate and provide a potential leakage pathway. This would correspond to a CO2 column height of ∼1,500 m, whereas the structural closure of the Tensleep Formation in the pilot injection area does not exceed 100 m. It is therefore apparent that CO2 injection is not likely to compromise the S1 fault stability. Better constraint of the least principal stress is needed to establish a more reliable estimate of the maximum reservoir pressure required to hydrofracture the caprock.  相似文献   

10.
Composite Portland cement–basalt caprock cores with fractures, as well as neat Portland cement columns, were prepared to understand the geochemical and geomechanical effects on the integrity of wellbores with defects during geologic carbon sequestration. The samples were reacted with CO2–saturated groundwater at 50 °C and 10 MPa for 3 months under static conditions, while one cement–basalt core was subjected to mechanical stress at 2.7 MPa before the CO2 reaction. Micro-XRD and SEM–EDS data collected along the cement–basalt interface after 3-month reaction with CO2–saturated groundwater indicate that carbonation of cement matrix was extensive with the precipitation of calcite, aragonite, and vaterite, whereas the alteration of basalt caprock was minor. X-ray microtomography (XMT) provided three-dimensional (3-D) visualization of the opening and interconnection of cement fractures due to mechanical stress. Computational fluid dynamics (CFD) modeling further revealed that this stress led to the increase in fluid flow and hence permeability. After the CO2-reaction, XMT images displayed that calcium carbonate precipitation occurred extensively within the fractures in the cement matrix, but only partially along the fracture located at the cement–basalt interface. The 3-D visualization and CFD modeling also showed that the precipitation of calcium carbonate within the cement fractures after the CO2-reaction resulted in the disconnection of cement fractures and permeability decrease. The permeability calculated based on CFD modeling was in agreement with the experimentally determined permeability. This study demonstrates that XMT imaging coupled with CFD modeling represent a powerful tool to visualize and quantify fracture evolution and permeability change in geologic materials and to predict their behavior during geologic carbon sequestration or hydraulic fracturing for shale gas production and enhanced geothermal systems.  相似文献   

11.
Structural traps like anticline structures are preferred for carbon dioxide sequestration as they limit lateral spreading of CO2 and thus provide localized storage. This study, therefore, assesses strategies for maximizing storage of CO2 using as hypothetical but realistic storage site a typical anticline structure in the North German sedimentary basin. Scenario simulations are performed to investigate the effects of well number, location, spacing and alignment, using fracture pressure and containment of CO2 within the anticline as constraining factors. Scenarios are ranked by stored CO2 mass, pressure increase due to injection and CO2 immobilized by dissolution or residual trapping. It is found that pressure overlap from different injectors influences CO2 migration considerably, limiting the storable amount to about 150 Mt, which represents half of the static capacity estimate.  相似文献   

12.
Supercritical CO2 (scCO2) is a good solvent for organic compounds such as benzene, toluene, ethyl-benzene, and xylene (BTEX), phenols, and polycyclic aromatic hydrocarbons (PAHs). Monitoring results from geological carbon sequestration (GCS) field tests have shown that organic compounds are mobilized following CO2 injection. Such results have raised concerns regarding the potential for groundwater contamination by toxic organic compounds mobilized during GCS. Knowledge of the mobilization mechanism of organic compounds and their transport and fate in the subsurface is essential for assessing risks associated with GCS. Extraction tests using scCO2 and methylene chloride (CH2Cl2) were conducted to study the mobilization of volatile organic compounds (VOCs, including BTEX), the PAH naphthalene, and n-alkanes by scCO2 from representative reservoir rock and caprock obtained from depleted oil reservoirs and coal from an enhanced coal-bed methane recovery site. Results showed that the extent of mobilization for the organic compounds was a function of the source rock. In fate and transport sand column experiments, moisture content was found to have an important influence on the transport of the organic compounds. In dry sand columns the majority of the compounds were retained in the column except benzene and toluene. In wet sand columns the mobility of the BTEX was much higher than that of naphthalene. Based upon the results determined for the reservoir rock, caprock, and coal samples studied here, the risk to aquifers from contamination by organic compounds appears to be relatively low; however, further work is necessary to fully evaluate the risks.  相似文献   

13.
The present paper provides a case study of the assessment of the potential for CO2 storage in the deep saline aquifers of the Bécancour region in southern Québec. This assessment was based on a hydrogeological and petrophysical characterization using existing and newly acquired core and well log data from hydrocarbon exploration wells. Analyses of data obtained from different sources provide a good understanding of the reservoir hydrogeology and petrophysics. Profiles of formation pressure, temperature, density, viscosity, porosity, permeability, and net pay were established for Lower Paleozoic sedimentary aquifers. Lateral hydraulic continuity is dominant at the regional scale, whereas vertical discontinuities are apparent for most physical and chemical properties. The Covey Hill sandstone appears as the most suitable saline aquifer for CO2 injection/storage. This unit is found at a depth of more than 1 km and has the following properties: fluid pressures exceed 14 MPa, temperature is above 35 °C, salinity is about 108,500 mg/l, matrix permeability is in the order of 3 × 10?16 m2 (0.3 mDarcy) with expected higher values of formation-scale permeability due to the presence of natural fractures, mean porosity is 6 %, net pay reaches 282 m, available pore volume per surface area is 17 m3/m2, rock compressibility is 2 × 10?9 Pa?1 and capillary displacement pressure of brine by CO2 is about 0.4 MPa. While the containment for CO2 storage in the Bécancour saline aquifers can be ensured by appropriate reservoir characteristics, the injectivity of CO2 and the storage capacity could be limiting factors due to the overall low permeability of aquifers. This characterization offers a solid basis for the subsequent development of a numerical hydrogeological model, which will be used for CO2 injection capacity estimation, CO2 injection scenarios and risk assessment.  相似文献   

14.
Geological sequestration is one of the most effective ways to reduce greenhouse gases, such as carbon dioxide (CO2). The deep oceanic crust dominated by ultrabasic rock could store CO2 permanently. However, the storage mechanism has not been thoroughly understood because of the limited amount of research and experiments conducted. This study explored the reactive mechanisms of water–rock–gas in an ultrabasic system under different conditions. Forsterite, the most dominant mineral found in ultrabasic reservoirs, was used to conduct laboratory physical simulation experiments. Two experimental systems were designed including an scCO2–forsterite–water system and an N2–forsterite–water system. All experiments were performed for 1000 h at an experimental temperature of 150°C and a pressure of 150 bar, respectively, to mimic the geological conditions. The liquid products from the experiments were analysed by inductively coupled plasma-optical emission spectrometry, whereas the solid samples were analysed by scanning electron microscopy with energy disperse spectroscopy. Results showed that: (1) in the early stage during scCO2/N2–forsterite–water interaction, forsterite was dissolved with a reactive transitional zone forming on the surface, which caused H+ to enter into the silicate framework and accelerated the reaction; (2) in the N2 system, the dissolution of forsterite was inhibited by the Mg2+ concentration after reaching its saturation in the late stage; and (3) in the scCO2 system, magnesite was precipitated as a secondary mineral during the late stage, which promoted the dissolution of forsterite. As a result, the degree of dissolution of forsterite in the scCO2 system was far higher than in the N2 system. The experimental results are consistent with the numerical simulation using TOUGHREACT, a geochemical simulation procedure, which showed that CO2 promotes the dissolution of forsterite greatly at high temperature and pressure.  相似文献   

15.
We propose a simple pressure test that can be used in the field to determine the effective permeability of existing wellbores. Such tests are motivated by the need to understand and quantify leakage risks associated with geological storage of CO2 in mature sedimentary basins. If CO2 is injected into a deep geological formation, and the resulting CO2 plume encounters a wellbore, leakage may occur through various pathways in the “disturbed zone” surrounding the well casing. The effective permeability of this composite zone, on the outside of the well casing, is an important parameter for models of leakage. However, the data that exist on this key parameter do not exist in the open literature, and therefore specific field tests need to be done in order to reduce the uncertainty inherent in the leakage estimates. The test designed and analyzed herein is designed to measure effective wellbore permeability within a low-permeability caprock, bounded above and below by permeable reservoirs, by pressurizing the reservoir below and measuring the response in the reservoir above. Alternatively, a modified test can be performed within the caprock without directly contacting the reservoirs above and below. We use numerical simulation to relate pressure response to effective well permeability and then evaluate the range of detection of the effective permeability based on instrument measurement error and limits on fracture pressure. These results can guide field experiments associated with site characterization and leakage analysis.  相似文献   

16.
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.  相似文献   

17.
In geological formations, migration of CO2 plume is very complex and irregular. To make CO2 capture and storage technology feasible, it is important to quantify CO2 amount associated with possible leakage through natural occurring faults and fractures in geologic medium. Present work examines the fracture aperture effect on CO2 migration due to free convection. Numerical results reveal that fracture with larger-aperture intensify CO2 leakage. Mathematical formulation and equations of state for the mixture are implemented within the object-oriented finite element code OpenGeoSys developed by the authors. The volume translated Peng–Robinson equation of state is used for material properties of CO2 and water.  相似文献   

18.
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.  相似文献   

19.
Deep brine recovery enhanced by supercritical CO2 injection is proposed to be a win–win method for the enhancement of brine production and CO2 storage capacity and security. However, the cross-flow through interlayers under different permeability conditions is not well investigated for a multi-layer aquifer system. In this work, a multi-layer aquifer system with different permeability conditions was built up to quantify the brine production yield and the leakage risk under both schemes of pure brine recovery and enhanced by supercritical CO2. Numerical simulation results show that the permeability conditions of the interlayers have a significant effect on the brine production and the leakage risk as well as the regional pressure. Brine recovery enhanced by supercritical CO2 injection can improve the brine production yield by a factor of 2–3.5 compared to the pure brine recovery. For the pure brine recovery, strong cross-flow through interlayers occurs due to the drastic and extensive pressure drop, even for the relative low permeability (k = 10?20 m2) mudstone interlayers. Brine recovery enhanced by supercritical CO2 can successfully manage the regional pressure and decrease the leakage risk, even for the relative high permeability (k = 10?17 m2) mudstone interlayers. In addition, since the leakage of brine mainly occurs in the early stage of brine production, it is possible to minimize the leakage risk by gradually decreasing the brine production pressure at the early stage. Since the leakage of CO2 occurs in the whole production period and is significantly influenced by the buoyancy force, it may be more effective by adopting horizontal wells and optimizing well placement to reduce the CO2 leakage risk.  相似文献   

20.
The Triassic–Jurassic South Georgia Rift (SGR) Basin, buried beneath Coastal Plain sediments of southern South Carolina, southeastern Georgia, western Florida, and southern Alabama, consists of an assemblage of continental rift deposits (popularly called red beds), and mafic igneous rocks (basalt flows and diabase sills). The red beds are capped by basalts and/or diabase sills, and constitute the target for supercritical CO2 storage as part of a Department of Energy funded project to study the feasibility for safe and permanent sequestration. The purpose of this research is to evaluate subsurface suitability for underground CO2 storage in terms of the local and regional distribution of porous and permeable reservoirs. In addition, unlike shale-capped CO2 reservoirs, very little is known about the ability of basalts and diabase sills to act as viable seals for CO2 storage. New results demonstrate the presence of confined porous rocks that may be capable of storing significant quantities of supercritical CO2. Reservoir thicknesses as high as 420 m and an average porosity as high as 14 % were obtained. The SGR Basin manifests distinct porosity–permeability regimes that are influenced by the depositional environments. These are: a high-porosity, medium/low-permeability zone associated with lacustrine deposits, a medium/low-porosity, low-permeability zone dominated by fluvial fine- to very fine-grained sandstone, and an extremely low porosity and permeability zone characterized by fluvial and alluvial-fan deposits. Analyses further show that the basalt flows and diabase sills are characterized by low porosity as well as high seismic velocities and densities that are favorable to caprock integrity.  相似文献   

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