首页 | 本学科首页   官方微博 | 高级检索  
相似文献
 共查询到20条相似文献，搜索用时 46 毫秒
1.
许雅琴  张可霓  王洋 《岩土力学》2012,33(12):3825-3832
咸水层CO2地质封存是减少大气中CO2排放量的有效途径。CO2注入率是衡量咸水层中CO2注入能力的有效因素,因此,研究注入速率的变化规律及提高的措施是很有工程价值的。在很多区域,地层的低渗透性限制了CO2的注入率。针对鄂尔多斯盆地的水文地质条件,通过数值模拟,探讨在低渗透性咸水层中提高CO2注入率的途径,包括改变储层中的盐度、采用水平井注入、增加注入井段的长度以及采取水力压裂等工程措施。其中改变储层中的盐度可通过在注入CO2前向储层中注入一定量的水来实现。模拟结果表明,这些方式可以有效地提高CO2注入率,其中水平井改造方式和水力压裂工程措施效果显著,盐度改造措施在地层初始含盐度较高时,会有更好的效果。研究结果可为鄂尔多斯盆地和类似地区的咸水层CO2地质封存项目提供参考。  相似文献   

2.
A variety of structural and stratigraphic factors control geological heterogeneity, inferred to influence both sequestration capacity and effectiveness, as well as seal capacity. Structural heterogeneity factors include faults, folds, and fracture intensity. Stratigraphic heterogeneity is primarily controlled by the geometry of depositional facies and sandbody continuity, which controls permeability structure. The permeability structure, in turn, has implications for CO2 injectivity and near-term migration pathways, whereas the long-term sequestration capacity can be inferred from the production history. Examples of Gulf Coast oil and gas reservoirs with differing styles of stratigraphic heterogeneity demonstrate the impact of facies variability on fluid flow and CO2 sequestration potential. Beach and barrier-island deposits in West Ranch field in southeast Texas are homogeneous and continuous. In contrast, Seeligson and Stratton fields in south Texas, examples of major heterogeneity in fluvial systems, are composed of discontinuous, channel-fill sandstones confined to narrow, sinuous belts. These heterogeneous deposits contain limited compartments for potential CO2 storage, although CO2 sequestration effectiveness may be enhanced by the high number of intraformational shale beds. These field examples demonstrate that areas for CO2 storage can be optimized by assessing sites for enhanced oil and gas recovery in mature hydrocarbon provinces.  相似文献   

3.
《China Geology》2022,5(3):359-371
To accelerate the achievement of China’s carbon neutrality goal and to study the factors affecting the geologic CO2 storage in the Ordos Basin, China’s National Key R&D Programs propose to select the Chang 6 oil reservoir of the Yanchang Formation in the Ordos Basin as the target reservoir to conduct the geologic carbon capture and storage (CCS) of 100000 t per year. By applying the basic theories of disciplines such as seepage mechanics, multiphase fluid mechanics, and computational fluid mechanics and quantifying the amounts of CO2 captured in gas and dissolved forms, this study investigated the effects of seven factors that influence the CO2 storage capacity of reservoirs, namely reservoir porosity, horizontal permeability, temperature, formation stress, the ratio of vertical to horizontal permeability, capillary pressure, and residual gas saturation. The results show that the sensitivity of the factors affecting the gas capture capacity of CO2 decreases in the order of formation stress, temperature, residual gas saturation, horizontal permeability, and porosity. Meanwhile, the sensitivity of the factors affecting the dissolution capture capacity of CO2 decreases in the order of formation stress, residual gas saturation, temperature, horizontal permeability, and porosity. The sensitivity of the influencing factors can serve as the basis for carrying out a reasonable assessment of sites for future CO2 storage areas and for optimizing the design of existing CO2 storage areas. The sensitivity analysis of the influencing factors will provide basic data and technical support for implementing geologic CO2 storage and will assist in improving geologic CO2 storage technologies to achieve China’s carbon neutralization goal.©2022 China Geology Editorial Office.  相似文献   

4.
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   

5.
Carbon Capture and Storage (CCS) is one of the effective means to deal with global warming, and saline aquifer storage is considered to be the most promising storage method. Junggar Basin, located in the northern part of Xinjiang and with a large distribution area of saline aquifer, is an effective carbon storage site. Based on well logging data and 2D seismic data, a 3D heterogeneous geological model of the Cretaceous Donggou Formation reservoir near D7 well was constructed, and dynamic simulations under two scenarios of single-well injection and multi-well injection were carried out to explore the storage potential and CO2 storage mechanism of deep saline aquifer with real geological conditions in this study. The results show that within 100 km2 of the saline aquifer of Donggou Formation in the vicinity of D7 well, the theoretical static CO2 storage is 71.967 × 106 tons (P50)①, and the maximum dynamic CO2 storage is 145.295 × 106 tons (Case2). The heterogeneity of saline aquifer has a great influence on the spatial distribution of CO2 in the reservoir. The multi-well injection scenario is conducive to the efficient utilization of reservoir space and safer for storage. Based on the results from theoretical static calculation and the dynamic simulation, the effective coefficient of CO2 storage in deep saline aquifer in the eastern part of Xinjiang is recommended to be 4.9%. This study can be applied to the engineering practice of CO2 sequestration in the deep saline aquifer in Xinjiang.  相似文献   

6.
Pressure buildup limits CO2 injectivity and storage capacity and pressure loss limits the brine production capacity and security, particularly for closed and semi-closed formations. In this study, we conduct a multiwell model to examine the potential advantages of combined exhaustive brine production and complete CO2 storage in deep saline formations in the Jiangling Depression, Jianghan Basin of China. Simulation results show that the simultaneous brine extraction and CO2 storage in saline formation not only effectively regulate near-wellbore and regional pressure of storage formation, but also can significantly enhance brine production capacity and CO2 injectivity as well as storage capacity, thereby achieving maximum utilization of underground space. In addition, the combination of brine production and CO2 injection can effectively mitigate the leakage risk between the geological units. With regard to the scheme of brine production and CO2 injection, constant pressure injection is much superior to constant rate injection thanks to the mutual enhancement effect. The simultaneous brine production of nine wells and CO2 injection of four wells under the constant pressure injection scheme act best in all respects of pressure regulation, brine production efficiency, CO2 injectivity and storage capacity as well as leakage risk mitigation. Several ways to further optimize the combined strategy are investigated and the results show that increasing the injection pressure and adopting fully penetrating production wells can further significantly enhance the combined efficiency; however, there is no obvious promoting effect by shortening the well spacing and changing the well placement.  相似文献   

7.
Basalt-hosted hydrogeologic systems have been proposed for geologic CO2 sequestration based on laboratory research suggesting rapid mineralization rates. However, despite this theoretical appeal, little is known about the impacts of basalt fracture heterogeneity on CO2 migration at commercial scales. Evaluating the suitability of basalt reservoirs is complicated by incomplete knowledge of in-situ fracture distributions at depths required for CO2 sequestration. In this work, a numerical experiment is used to investigate the effects of spatial reservoir uncertainty for geologic CO2 sequestration in the east Snake River Plain, Idaho (USA). Two criteria are investigated: (1) formation injectivity and (2) confinement potential. Several theoretical tools are invoked to develop a field-based approach for geostatistical reservoir characterization and their implementation is illustrated. Geologic CO2 sequestration is simulated for 10?years of constant-rate injection at ~680,000 tons per year and modeled by Monte Carlo simulation such that model variability is a function of spatial reservoir heterogeneity. Results suggest that the spatial distribution of heterogeneous permeability structures is a controlling influence on formation injectivity. Analysis of confinement potential is less conclusive; however, in the absence of confining sedimentary interbeds within the basalt pile, rapid mineralization may be necessary to reduce the risk of escape.  相似文献   

8.
Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO2 storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO2-brine systems at in-situ conditions is essential in ascertaining CO2 injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO2 storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO2-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO2-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.  相似文献   

9.
Carbon sequestration in shallow aquifers can be facilitated by water withdrawal. The factors that optimize the injection/withdrawal balance to minimize potential environmental impacts have been studied, including reservoir size, well pattern, injection rate, reservoir heterogeneity, anisotropy ratio, and permeability sequence. The effects of these factors on CO2 storage capacity and efficiency were studied using a compositional simulator Computer Modeling Group-General Equation of State Model, which modeled features including residual gas trapping, CO2 solubility, and mineralization reactions. Two terms, storage efficiency and CO2 relative breakthrough time, were introduced to better describe the problem. The simulation results show that simultaneous water withdrawal during CO2 injection greatly improves CO2 storage capacity and efficiency. A certain degree of heterogeneity or anisotropy benefits CO2 storage. A high injection rate favors storage capacity, but reduces the storage efficiency and CO2 breakthrough time, which in turn limits the total amount of CO2 injected.  相似文献   

10.
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   

11.
The feasibility of CO2 storage and enhanced gas recovery (EGR) effects in the mature Altmark natural gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO2 as well as reservoir simulation studies to evaluate the CO2 wellbore injectivity and displacement efficiency of the residual gas by the injected CO2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO2 gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO2 will be maximized. The migration/extension of CO2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO2 extension and pressure propagation suggested no breakthrough of CO2 at the prospective production well during the 3-year injection period studied.  相似文献   

12.
Geological storage of CO2 in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO2 emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.  相似文献   

13.
A long-term (up to 10 ka) geochemical change in saline aquifer CO2 storage was studied using the TOUGHREACT simulator, on a 2-dimensional, 2-layered model representing the underground geologic and hydrogeologic conditions of the Tokyo Bay area that is one of the areas of the largest CO2 emissions in the world. In the storage system characterized by low permeability of reservoir and cap rock, the dominant storage mechanism is found to be solubility trapping that includes the dissolution and dissociation of injected CO2 in the aqueous phase followed by geochemical reactions to dissolve minerals in the rocks. The CO2–water–rock interaction in the storage system (mainly in the reservoir) changes the properties of water in a mushroom-like CO2 plume, which eventually leads to convective mixing driven by gravitational instability. The geochemically evolved aqueous phase precipitates carbonates in the plume front due to a local rise in pH with mixing of unaffected reservoir water. The carbonate precipitation occurs extensively within the plume after the end of its enlargement, fixing injected CO2 in a long, geologic period.Dawsonite, a Na–Al carbonate, is initially formed throughout the plume from consumption of plagioclase in the reservoir rock, but is found to be a transient phase finally disappearing from most of the CO2-affected part of the system. The mineral is unstable relative to more common types of carbonates in the geochemical evolution of the CO2 storage system initially having formation water of relatively low salinity. The exception is the reservoir-cap rock boundary where CO2 saturation remains very high throughout the simulation period.  相似文献   

14.
A new uncertainty quantification framework is adopted for carbon sequestration to evaluate the effect of spatial heterogeneity of reservoir permeability on CO2 migration. Sequential Gaussian simulation is used to generate multiple realizations of permeability fields with various spatial statistical attributes. In order to deal with the computational difficulties, the following ideas/approaches are integrated. First, different efficient sampling approaches (probabilistic collocation, quasi-Monte Carlo, and adaptive sampling) are used to reduce the number of forward calculations, explore effectively the parameter space, and quantify the input uncertainty. Second, a scalable numerical simulator, extreme-scale Subsurface Transport Over Multiple Phases, is adopted as the forward modeling simulator for CO2 migration. The framework has the capability to quantify input uncertainty, generate exploratory samples effectively, perform scalable numerical simulations, visualize output uncertainty, and evaluate input-output relationships. The framework is demonstrated with a given CO2 injection scenario in heterogeneous sandstone reservoirs. Results show that geostatistical parameters for permeability have different impacts on CO2 plume radius: the mean parameter has positive effects at the top layers, but affects the bottom layers negatively. The variance generally has a positive effect on the plume radius at all layers, particularly at middle layers, where the transport of CO2 is highly influenced by the subsurface heterogeneity structure. The anisotropy ratio has weak impacts on the plume radius, but affects the shape of the CO2 plume.  相似文献   

15.
Geochemical detection of carbon dioxide in dilute aquifers   总被引：1，自引：0，他引：1  

Background  

Carbon storage in deep saline reservoirs has the potential to lower the amount of CO2 emitted to the atmosphere and to mitigate global warming. Leakage back to the atmosphere through abandoned wells and along faults would reduce the efficiency of carbon storage, possibly leading to health and ecological hazards at the ground surface, and possibly impacting water quality of near-surface dilute aquifers. We use static equilibrium and reactive transport simulations to test the hypothesis that perturbations in water chemistry associated with a CO2 gas leak into dilute groundwater are important measures for the potential release of CO2 to the atmosphere. Simulation parameters are constrained by groundwater chemistry, flow, and lithology from the High Plains aquifer. The High Plains aquifer is used to represent a typical sedimentary aquifer overlying a deep CO2 storage reservoir. Specifically, we address the relationships between CO2 flux, groundwater flow, detection time and distance. The CO2 flux ranges from 103 to 2 × 106 t/yr (0.63 to 1250 t/m2/yr) to assess chemical perturbations resulting from relatively small leaks that may compromise long-term storage, water quality, and surface ecology, and larger leaks characteristic of short-term well failure.  相似文献   

16.
This study presents the Bottom-hole pressure (BHP) behavior with different wettabilities and the optimal design scheme to effectively inject CO2 into the Gorae-V aquifer. As a result, the injection rate and injectivity were increased as the wettability condition became more water-wet. However, the more wettability condition becomes water-wet, the more the ultimate CO2 injection volume decreases. When the injectivity was 346 ton/day/Mpa at the Gorae-V aquifer, the aquifer can sustain CO2 injection at a rate of 2,425 tons per day over this time period. A design for a complete CCS system was developed based on the existing off-shore pipeline in combination with new on-shore CO2 transport infrastructure, and a pressure of 12.8 MPa is required at the CO2 source to maintain this injection rate.  相似文献   

17.
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   

18.
Capturing CO2 from point sources and storing it in geologic formations is a potential option for allaying the CO2 level in the atmosphere. In order to evaluate the effect of geological storage of CO2 on rock-water interaction, batch experiments were performed on sandstone samples taken from the Altmark reservoir, Germany, under in situ conditions of 125 °C and 50 bar CO2 partial pressure. Two sets of experiments were performed on pulverized sample material placed inside a closed batch reactor in (a) CO2 saturated and (b) CO2 free environment for 5, 9 and 14 days. A 3M NaCl brine was used in both cases to mimic the reservoir formation water. For the “CO2 free” environment, Ar was used as a pressure medium. The sandstone was mainly composed of quartz, feldspars, anhydrite, calcite, illite and chlorite minerals. Chemical analyses of the liquid phase suggested dissolution of both calcite and anhydrite in both cases. However, dissolution of calcite was more pronounced in the presence of CO2. In addition, the presence of CO2 enhanced dissolution of feldspar minerals. Solid phase analysis by X-ray diffraction and Mössbauer spectroscopy did not show any secondary mineral precipitation. Moreover, Mössbauer analysis did not show any evidence of significant changes in redox conditions. Calculations of total dissolved solids’ concentrations indicated that the extent of mineral dissolution was enhanced by a factor of approximately 1.5 during the injection of CO2, which might improve the injectivity and storage capacity of the targeted reservoir. The experimental data provide a basis for numerical simulations to evaluate the effect of injected CO2 on long-term geochemical alteration at reservoir scale.  相似文献   

19.
Reservoir and cap-rock core samples with variable lithology's representative of siliciclastic reservoirs used for CO2 storage have been characterized and reacted at reservoir conditions with an impure CO2 stream and low salinity brine. Cores from a target CO2 storage site in Queensland, Australia were tested. Mineralogical controls on the resulting changes to porosity and water chemistry have been identified. The tested siliciclastic reservoir core samples can be grouped generally into three responses to impure CO2-brine reaction, dependent on mineralogy. The mineralogically clean quartzose reservoir cores had high porosities, with negligible change after reaction, in resolvable porosity or mineralogy, calculated using X-ray micro computed tomography and QEMSCAN. However, strong brine acidification and a high concentration of dissolved sulphate were generated in experiments owing to minimal mineral buffering. Also, the movement of kaolin has the potential to block pore throats and reduce permeability. The reaction of the impure CO2-brine with calcite-cemented cap-rock core samples caused the largest porosity changes after reaction through calcite dissolution; to the extent that one sample developed a connection of open pores that extended into the core sub-plug. This has the potential to both favor injectivity but also affect CO2 migration. The dissolution of calcite caused the buffering of acidity resulting in no significant observable silicate dissolution. Clay-rich cap-rock core samples with minor amounts of carbonate minerals had only small changes after reaction. Created porosity appeared mainly disconnected. Changes were instead associated with decreases in density from Fe-leaching of chlorite or dissolution of minor amounts of carbonates and plagioclase. The interbedded sandstone and shale core also developed increased porosity parallel to bedding through dissolution of carbonates and reactive silicates in the sandy layers. Tight interbedded cap-rocks could be expected to act as baffles to fluids preventing vertical fluid migration. Concentrations of dissolved elements including Ca, Fe, Mn, and Ni increased during reactions of several core samples, with Mn, Mg, Co, and Zn correlated with Ca from cap-rock cores. Precipitation of gypsum, Fe-oxides and clays on seal core samples sequestered dissolved elements including Fe through co-precipitation or adsorption. A conceptual model of impure CO2-water-rock interactions for a siliciclastic reservoir is discussed.  相似文献   

20.
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   

设为首页 | 免责声明 | 关于勤云 | 加入收藏

Copyright©北京勤云科技发展有限公司  京ICP备09084417号