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1.
In this paper, Shell’s in-house reservoir simulator MoReS is applied to a recently introduced CO2 sequestration benchmark problem entitled “Estimation of the CO2 Storage Capacity of a Geological Formation” (Class et al. 2008). The principal objective of this benchmark is the simulation of CO2 distribution within a modeling region, and leakage of CO2 outside of it, for a period of 50 years. This study goes beyond the benchmarking exercise to investigate additional factors with direct relevance to CO2 storage capacity estimations: water and gas relative permeabilities, permeability anisotropy, presence of sub-seismic features (conductive fractures, thin shale layers), regional hydrodynamic gradient, CO2-enriched brine convection (due to brine density differences), and injection rates. The effects of hydrodynamic gradients and gravitationally induced convection only become significant over 100 s of years. This study has thus extended simulation time to 1,000 years. It is shown that grid resolution significantly impacts results. Vertical-grid refinement results in larger and thinner CO2 plumes. Lateral-grid refinement delays leakage out of the model domain and reduces injection pressure for a given injection rate. Sub-seismic geological features such as fractures/faults and shale layers are demonstrated to have impact on CO2 sequestration. Fractures located up-dip from the injector may lead to more leakage while the opposite may happen in the presence of fractures perpendicular to the dip. Thin shale layers produce stacked CO2 blankets. They should be explicitly represented instead of being upscaled using a reduced vertical to horizontal permeability ratio. Results are seen to be far more sensitive to gas relative permeability and hysteresis than to variations in the water relative permeability models used. For a multi-injectors project, there is scope to optimize the phasing of injections to avoid potential fracturing near injectors.  相似文献   

2.
With heightened concerns on CO2 emissions from pulverized-coal (PC) power plants, there has been major emphasis in recent years on the development of safe and economical geological carbon sequestration (GCS) technology. Saline aquifers are considered very attractive for GCS because of their large storage capacity in U.S. and other parts of the world for long-term sequestration. However, uncertainties about storage efficiency as well as leakage risks remain major areas of concern that need to be addressed before the saline aquifers can be fully exploited for carbon sequestration. A genetic algorithm-based optimizer has been developed and coupled with the well-known multiphase numerical solver TOUGH2 to optimally examine various injection strategies for increasing the CO2 storage efficiency as well as for reducing its plume migration. The optimal injection strategies for CO2 injection employing a vertical injection well and a horizontal injection well are considered. To ensure the accuracy of the results, the combined hybrid numerical solver/optimizer code was validated by conducting simulations of three widely used benchmark problems employed by carbon sequestration researchers worldwide. The validated code is then employed to optimize the proposed water-alternating-gas injection scheme for CO2 sequestration using both the vertical and the horizontal injection wells. The results suggest the potential benefits of CO2 migration control and dissolution. The optimization capability of the hybrid code holds a great promise in studying a host of other problems in GCS, namely how to optimally enhance capillary trapping, accelerate the dissolution of CO2 in water or brine, and immobilize the CO2 plume.  相似文献   

3.
The joint research project CLEAN was conducted in the years 2008?C2011 by a German research and development (R&D) alliance of 16 partners from science and industry. The project was set-up as pilot project to investigate the processes relevant to enhanced gas recovery (EGR) by the injection of CO2 into a subfield of the almost depleted Altmark natural gas field. Despite the setback that permission for active injection was not issued by the mining authority during the period of the project, important results fostering the understanding of processes linked with EGR were achieved. Work carried out led to a comprehensive evaluation of the EGR potential of the Altmark field and the Altensalzwedel subfield in particular. The calculated safety margins emphasize that technical well integrity of the 12 examined boreholes is given for EGR without a need for any further intervention. The laboratory and field tests confirm that the Altensalzwedel subfield is suitable for the injection of 100,000?t of CO2. Numerical simulations provide sound predictions for the efficiency and safety of the EGR technology based on the CO2 injection. The development and testing of different monitoring techniques facilitate an improved surveying of CO2 storage sites in general. The CLEAN results provide the technological, logistic and conceptual prerequisites for implementing a CO2-based EGR project in the Altmark and provide a benchmark for similar projects in the world.  相似文献   

4.
Deep saline aquifers still remain a significant option for the disposal of large amounts of CO2 from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO2 plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO2 gas saturation and mass fraction of dissolved CO2 in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO2 injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO2 injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO2 plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO2–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO2 injection scheme still requires pursuance of further studies.  相似文献   

5.
Geologic CO2 sequestration in deep saline aquifers is a promising technique to mitigate the effect of greenhouse gas emissions. Designing optimal CO2 injection strategy becomes a challenging problem in the presence of geological uncertainty. We propose a surrogate assisted optimisation technique for robust optimisation of CO2 injection strategies. The surrogate is built using Adaptive Sparse Grid Interpolation (ASGI) to accelerate the optimisation of CO2 injection rates. The surrogate model is adaptively built with different numbers of evaluation points (simulation runs) in different dimensions to allow automatic refinement in the dimension where added resolution is needed. This technique is referred to as dimensional adaptivity and provides a good balance between the accuracy of the surrogate model and the number of simulation runs to save computational costs. For a robust design, we propose a utility function which comprises the statistical moment of the objective function. Numerical testing of the proposed approach applied to benchmark functions and reservoir models shows the efficiency of the method for the robust optimisation of CO2 injection strategies under geological uncertainty.  相似文献   

6.
This study examined the impacts of reservoir properties on carbon dioxide (CO2) migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO2 monitoring data such as spatial–temporal distributions of gas pressure, which can be reasonably monitored in practice. The injection reservoir was assumed to be located 1,400–1,500 m below the ground surface such that CO2 remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended out 8,000 m from the injection well. The CO2 migration was simulated using the latest version of the simulator, subsurface transport over multiple phases (the water–salt–CO2–energy module), developed by Pacific Northwest National Laboratory. A nonlinear parameter estimation and optimization modeling software package, Parameter ESTimation (PEST), is adopted for automated reservoir parameter estimation. The effects of data quality, data worth, and data redundancy were explored regarding the detectability of reservoir parameters using gas pressure monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy. The feasibility of using CO2 saturation data for improving reservoir characterization was also discussed.  相似文献   

7.
The paper presents a comparison of hydrologic issues and technical approaches used in deep-well injection and disposal of liquid wastes, and those issues and approaches associated with injection and storage of CO2 in deep brine formations. These comparisons have been discussed in nine areas: injection well integrity; abandoned well problems; buoyancy effects; multiphase flow effects; heterogeneity and flow channeling; multilayer isolation effects; caprock effectiveness and hydromechanics; site characterization and monitoring; effects of CO2 storage on groundwater resources. There are considerable similarities, as well as significant differences. Scientifically and technically, these two fields can learn much from each other. The discussions presented in this paper should help to focus on the key scientific issues facing deep injection of fluids. A substantial but by no means exhaustive reference list has been provided for further studies into the subject.  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 is devoted to experimental investigations of the hydro-mechanical–chemical coupling behaviour of sandstone in the context of CO2 storage in aquifers. We focused on the evolution of creep strain, the transport properties and the elastic modulus of sandstone under the effect of CO2–brine or CO2 alone. A summary of previous laboratory results is first presented, including mechanical, poromechanical and hydro-mechanical–chemical coupling properties. Tests were then performed to investigate the evolution of the creep strain and permeability during the injection of CO2–brine or CO2 alone. After the injection of CO2–brine or CO2 alone, an instantaneous volumetric dilatancy was observed due to the decrease in the effective confining stress. However, CO2 alone had a significant influence on the creep strain and permeability compared to the small influence of CO2–brine. This phenomenon can be attributed to the acceleration of the CO2–brine–rock reaction by the generation of carbonic acid induced by the dissolution of CO2 into the brine. The original indentation tests on samples after the CO2–brine–rock reaction were also performed and indicated that the elastic modulus decreased with an increasing reaction time. The present laboratory results can advance our knowledge of the hydro-mechanical–chemical coupling behaviour of sandstone in CO2 storage in aquifers.  相似文献   

10.
Large-scale implementation of geological CO2 sequestration requires quantification of risk and leakage potential. One potentially important leakage pathway for the injected CO2 involves existing oil and gas wells. Wells are particularly important in North America, where more than a century of drilling has created millions of oil and gas wells. Models of CO2 injection and leakage will involve large uncertainties in parameters associated with wells, and therefore a probabilistic framework is required. These models must be able to capture both the large-scale CO2 plume associated with the injection and the small-scale leakage problem associated with localized flow along wells. Within a typical simulation domain, many hundreds of wells may exist. One effective modeling strategy combines both numerical and analytical models with a specific set of simplifying assumptions to produce an efficient numerical–analytical hybrid model. The model solves a set of governing equations derived by vertical averaging with assumptions of a macroscopic sharp interface and vertical equilibrium. These equations are solved numerically on a relatively coarse grid, with an analytical model embedded to solve for wellbore flow occurring at the sub-gridblock scale. This vertical equilibrium with sub-scale analytical method (VESA) combines the flexibility of a numerical method, allowing for heterogeneous and geologically complex systems, with the efficiency and accuracy of an analytical method, thereby eliminating expensive grid refinement for sub-scale features. Through a series of benchmark problems, we show that VESA compares well with traditional numerical simulations and to a semi-analytical model which applies to appropriately simple systems. We believe that the VESA model provides the necessary accuracy and efficiency for applications of risk analysis in many CO2 sequestration problems.  相似文献   

11.
Technology of CO2 capture and sequestration (CCS) is one of the many solutions to reduce greenhouse gases and alleviate the current global warming, but its security is important and needs to be evaluated. A simulator which links TOUGHREACT and FLAC3D was used to simulate the process of coupled temperature-hydrologic-mechanics (THM) in CCS. A test on laboratory scale was set up and water was injected into compacted sand covered by low permeability clay to study the land uplift displacement. The results were used to verify the accuracy of the simulator for calculating the THM coupling. The effects of injection quantity, injection time, and injection mode on land uplift were also studied on the constructed model. At last, a land uplift evaluation system was built to quantify the CO2 escape if any. The evaluation process can be divided into five steps: model generalization, acquisition of model parameters, numerical modeling, simulation and analysis, monitor comparison, and evaluation of model results. The major output of this study will provide a feasible method for quantitative analysis of CO2 leakage in CCS projects.  相似文献   

12.
A laboratory geochemical study was conducted using a drill core sample of cap rock from the Surat Basin, Australia, to investigate the effect of NO2 contained in the CO2 gas exhausted from the oxyfuel combustion process (oxyfuel combustion CO2) on the cap rock. A gas (CO2 containing NO2) was prepared to simulate the exhaust gas produced from the oxyfuel combustion process. Two types of gases (pure CO2 and CO2 containing SO2) were also prepared as reference gases. The effect of NO2 on cap rock was studied experimentally using these gases. No differences in the amounts of leached ions and pH changes for CO2 containing NO2 (36 ppmv), pure CO2, and CO2 containing SO2 (35 ppmv) existed. The pH values decreased immediately after CO2 gas injection but increased with time as a result of mineral buffering. Leaching of Fe, Mg, Ca, and K was suggested to have occurred as the result of dissolution of Fe-chlorite, prehnite and illite-smectite mixed layer clay in the shale sample. The amounts of Ca, Fe, and Mg leached with CO2 containing NO2 (318 ppmv) were higher than those for pure CO2. For the mixture containing 318 ppmv NO2, the pH increased more than that for the other gas conditions immediately after the pH fall at the start of the experiment, because oxidation-reduction reactions occurred between Fe2+ and NO3−. Moreover, the results indicated that some of the leached Ca and Fe were deposited on the shale sample because of the pH increase. Therefore, we concluded that the effects of NO2 on mineral dissolution and pH changes of formation water are negligible when oxyfuel combustion CO2 containing about 30 ppmv of NO2 is injected into an underground aquifer. In addition, even if about 300 ppmv NO2 is accidentally injected into the underground aquifer, mineral dissolution is suppressed due to the buffering of pH decrease after gas injection.  相似文献   

13.
CO2 storage in geological formations is currently being discussed intensively as a technology with a high potential for mitigating CO2 emissions. However, any large-scale application requires a thorough analysis of the potential risks. Current numerical simulation models are too expensive for probabilistic risk analysis or stochastic approaches based on a brute-force approach of repeated simulation. Even single deterministic simulations may require parallel high-performance computing. The multiphase flow processes involved are too non-linear for quasi-linear error propagation and other simplified stochastic tools. As an alternative approach, we propose a massive stochastic model reduction based on the probabilistic collocation method. The model response is projected onto a higher-order orthogonal basis of polynomials to approximate dependence on uncertain parameters (porosity, permeability, etc.) and design parameters (injection rate, depth, etc.). This allows for a non-linear propagation of model uncertainty affecting the predicted risk, ensures fast computation, and provides a powerful tool for combining design variables and uncertain variables into one approach based on an integrative response surface. Thus, the design task of finding optimal injection regimes explicitly includes uncertainty, which leads to robust designs with a minimum failure probability. We validate our proposed stochastic approach by Monte Carlo simulation using a common 3D benchmark problem (Class et al., Comput Geosci 13:451–467, 2009). A reasonable compromise between computational efforts and precision was reached already with second-order polynomials. In our case study, the proposed approach yields a significant computational speed-up by a factor of 100 compared with the Monte Carlo evaluation. We demonstrate that, due to the non-linearity of the flow and transport processes during CO2 injection, including uncertainty in the analysis leads to a systematic and significant shift of the predicted leakage rates toward higher values compared with deterministic simulations, affecting both risk estimates and the design of injection scenarios.  相似文献   

14.
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   

15.
Sedimentary porous rocks can be used for long-term subsurface containment of CO2. Before injecting CO2 to sedimentary reservoirs, it is necessary to perform stability analysis of the reservoir and to estimate the maximum sustainable pore fluid pressures. In order to avoid the reservoir damage during the CO2 injection, the effective stresses in the reservoir should be evaluated. In this paper, numerical modeling techniques are used for the evaluation of stresses and deformations in a naturally fractured carbonate sedimentary reservoir. The developed numerical modeling scheme couples the behavior of the CO2 injection and the change in the geomechanical behavior of the sedimentary carbonate reservoir for a case study from Saudi Arabia. The present investigation extends the previous studies by considering the sorption-based deformation during the injection of the compressed CO2 fluid into the Arab-D naturally fractured carbonate reservoir. The change in permeability during the injection of CO2 is evaluated. The adopted CO2 injection scenario was shown to be within the safe maximum occupancy, and that the increase in the pore pressure does not result in the reservoir failure.  相似文献   

16.
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   

17.
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   

18.
Geological sequestration of CO2 into depleted hydrocarbon reserviors or saline aquifers presents the enormous potential to reduce greenhouse gas emission from fossil fuels. However, it may give rise to a complicated coupling physical and chemical process. One of the processes is the hydro-mechanical impact of CO2 injection. During the injection project, the increase of pore pressures of storing formations can induce the instability, which finally results in a catastrophic failure of disposal sites. This paper focuses mainly on the role of CO2-saturated water in the fracturing behavior of rocks. To investigate how much the dissolved CO2 can influence the pore pressure change of rocks, acoustic emission (AE) experiments were performed on sandstone and granite samples under triaxial conditions. The main innovation of this paper is to propose a time dependent porosity method to simulate the abrupt failure process, which is observed in the laboratory and induced by the pore pressure change due to the volume dilatancy of rocks, using a finite element scheme associated with two-phase characteristics. The results successfully explained the phenomena obtained in the physical experiments.  相似文献   

19.
This study reports the first field test of a multi-channel, auto-dilution, steady-state, soil–CO2 flux monitoring system being developed to help understand the pathways by which fugitive CO2 from a geologic sequestration site migrates to the surface. The test was conducted from late August through mid-October 2008 at the Zero Emissions Research and Technology project site located in Bozeman, MT. Twenty steady-state and five non-steady-state flux chambers were installed in a 10 × 15 m area, one boundary of which was directly above a shallow (2-m depth) horizontal injection well located 0.5 m below the water table. A total flux of 52 kg CO2 day−1 was injected into the well for 13 days and the efflux from the soil was monitored by the chambers before, during, and for 33 days after the injection. The results showed a rapid increase in soil efflux once injection started, with maximal values reached within 3–7 days in most chambers. Efflux returned to background levels within a similar time period after injection ceased. A radial efflux pattern was observed to at least 2 m from the injection well, and evidence for movement of the CO2 plume during the injection, presumably due to groundwater flow, was seen. The steady-state chambers yielded very stable data, but threefold to fivefold higher fluxes than the non-steady-state chambers. The higher fluxes were attributed to vacuum induced in the steady-state chambers by narrow vent tubes. High winds resulted in significant decreases in measured soil CO2 efflux, presumably by enhancing efflux from soil outside the chambers.  相似文献   

20.
Characterization of coal reservoirs and determination of in-situ physical coal properties related to transport mechanism are complicated due to having lack of standard procedures in the literature. By considering these difficulties, a new approach has been developed proposing the usage of relationships between coal rank and physical coal properties. In this study, effects of shrinkage and swelling (SS) on total methane recovery at CO2 breakthrough (TMRB), which includes ten-year primary methane recovery and succeeding enhanced coalbed methane (ECBM) recovery up to CO2 breakthrough, and CO2 sequestration have been investigated by using rank-dependent coal properties. In addition to coal rank, different coal reservoir types, molar compositions of injected fluid, and parameters within the extended Palmer & Mansoori (P&M) permeability model were considered. As a result of this study, shrinkage and swelling lead to an increase in TMRB. Moreover, swelling increased CO2 breakthrough time and decreased displacement ratio and CO2 storage for all ranks of coal. Low-rank coals are affected more negatively than high-rank coals by swelling. Furthermore, it was realized that dry coal reservoirs are more influenced by swelling than others and saturated wet coals are more suitable for eliminating the negative effects of CO2 injection. In addition, it was understood that it is possible to reduce swelling effect of CO2 on cleat permeability by mixing it with N2 before injection. However, an economical optimization is required for the selection of proper gas mixture. Finally, it is concluded from sensitivity analysis that elastic modulus is the most important parameter, except the initial cleat porosity, controlling SS in the extended P&M model by highly affecting TMRB.  相似文献   

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