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1.
The modes of geologic storage of CO 2 are usually categorized as structural, dissolution, residual, and mineral trapping. Here we argue that the heterogeneity
intrinsic to sedimentary rocks gives rise to a fifth category of storage, which we call local capillary trapping. Local capillary
trapping occurs during buoyancy-driven migration of bulk phase CO 2 within a saline aquifer. When the rising CO 2 plume encounters a region (10 −2 to 10 +1m) where capillary entry pressure is locally larger than average, CO 2 accumulates beneath the region. This form of storage differs from structural trapping in that much of the accumulated saturation
will not escape, should the integrity of the seal overlying the aquifer be compromised. Local capillary trapping differs from
residual trapping in that the accumulated saturation can be much larger than the residual saturation for the rock. We examine
local capillary trapping in a series of numerical simulations. The essential feature is that the drainage curves (capillary
pressure versus saturation for CO 2 displacing brine) are required to be consistent with permeabilities in a heterogeneous domain. In this work, we accomplish
this with the Leverett J-function, so that each grid block has its own drainage curve, scaled from a reference curve to the permeability and porosity
in that block. We find that capillary heterogeneity controls the path taken by rising CO 2. The displacement front is much more ramified than in a homogeneous domain, or in a heterogeneous domain with a single drainage
curve. Consequently, residual trapping is overestimated in simulations that ignore capillary heterogeneity. In the cases studied
here, the reduction in residual trapping is compensated by local capillary trapping, which yields larger saturations held
in a smaller volume of pore space. Moreover, the amount of CO 2 phase remaining mobile after a leak develops in the caprock is smaller. Therefore, the extent of immobilization in a heterogeneous
formation exceeds that reported in previous studies of buoyancy-driven plume movement. 相似文献
2.
Carbon storage in saline formations is considered as a promising option to ensure the necessary decrease of CO 2 anthropogenic emissions. Its industrial development in those formations is above all conditioned by its safety demonstration.
Assessing the evolution of trapped and mobile CO 2 across time is essential in the perspective of reducing leakage risks. In this work, we focus on residual trapping phenomenon
occurring during the wetting of the injected CO 2 plume. History dependent effects are of first importance when dealing with capillary trapping. We then apply the classical
fractional flow theory (Buckley–Leverett type model) and include trapping and hysteresis models; we derive an analytical solution
for the temporal evolution of saturation profile and of CO 2 trapped quantity when injecting water after the gas injection (“artificial imbibition”). The comparison to numerical simulations
for different configurations shows satisfactory match and justifies, in the case of industrial CO 2 storage, the assumptions of incompressible flow with no consideration of capillary pressure. The obtained analytical solution
allows the quick assessment of both the quantity and the location of mobile gas left during imbibition. 相似文献
3.
Sequestration of carbon dioxide in geological formations is an alternative way of managing extra carbon. Although there are
a number of mathematical modeling studies related to this subject, experimental studies are limited and most studies focus
on injection into sandstone reservoirs as opposed to carbonate ones. This study describes a fully coupled geochemical compositional
equation-of-state compositional simulator (STARS) for the simulation of CO 2 storage in saline aquifers. STARS models physical phenomena including (1) thermodynamics of sub- and supercritical CO 2, and PVT properties of mixtures of CO 2 with other fluids, including (saline) water; (2) fluid mechanics of single and multiphase flow when CO 2 is injected into aquifers; (3) coupled hydrochemical effects due to interactions between CO 2, reservoir fluids, and primary mineral assemblages; and (4) coupled hydromechanical effects, such as porosity and permeability
change due to the aforementioned blocking of pores by carbonate particles and increased fluid pressures from CO 2 injection. Matching computerized tomography monitored laboratory experiments showed the uses of the simulation model. In
the simulations dissolution and deposition of calcite as well as adsorption of CO 2 that showed the migration of CO 2 and the dissociation of CO 2 into HCO 3 and its subsequent conversion into carbonate minerals were considered. It was observed that solubility and hydrodynamic storage
of CO 2 is larger compared to mineral trapping. 相似文献
4.
Onset of double-diffusive buoyancy-driven flow resulted from vertical temperature and concentration gradients in a horizontal
layer of a saturated and homogenous porous medium is investigated using amplification factor theory. After injection of CO 2 into a deep saline aquifer, the density of the brine saturated with CO 2 increases slightly. This increase in density induces natural convection. The effect of geothermal gradient is also considered
in this work as a second incentive for convection and the double-diffusion convection was studied. Linear stability analysis
is used to predict the inception of instabilities and initial wavelength of the convective instabilities. The analysis presented
is applied to acid gas injection (as an analogue for CO 2 storage) into saline aquifers in the Alberta basin. It is found that the geothermal gradient does not have significant effect
on the onset of convection for these aquifers. It is shown that the geothermal effects on the onset of natural convection
are negligible as compared to the solutal effects induced by dissolution and diffusion of CO 2 in deep saline aquifers. Therefore, the linear stability analysis and the long-term numerical simulation of CO 2 sequestration into such saline aquifers may be assumed to be isothermal in terms of natural convection occurrence. 相似文献
5.
Dissolution of CO 2 into brine is an important and favorable trapping mechanism for geologic storage of CO 2. There are scenarios, however, where dissolved CO 2 may migrate out of the storage reservoir. Under these conditions, CO 2 will exsolve from solution during depressurization of the brine, leading to the formation of separate phase CO 2. For example, a CO 2 sequestration system with a brine-permeable caprock may be favored to allow for pressure relief in the sequestration reservoir.
In this case, CO 2-rich brine may be transported upwards along a pressure gradient caused by CO 2 injection. Here we conduct an experimental study of CO 2 exsolution to observe the behavior of exsolved gas under a wide range of depressurization. Exsolution experiments in highly
permeable Berea sandstones and low permeability Mount Simon sandstones are presented. Using X-ray CT scanning, the evolution
of gas phase CO 2 and its spatial distribution is observed. In addition, we measure relative permeability for exsolved CO 2 and water in sandstone rocks based on mass balances and continuous observation of the pressure drop across the core from
12.41 to 2.76 MPa. The results show that the minimum CO 2 saturation at which the exsolved CO 2 phase mobilization occurs is from 11.7 to 15.5%. Exsolved CO 2 is distributed uniformly in homogeneous rock samples with no statistical correlation between porosity and CO 2 saturation observed. No gravitational redistribution of exsolved CO 2 was observed after depressurization, even in the high permeability core. Significant differences exist between the exsolved
CO 2 and water relative permeabilities, compared to relative permeabilities derived from steady-state drainage relative permeability
measurements in the same cores. Specifically, very low CO 2 and water relative permeabilities are measured in the exsolution experiments, even when the CO 2 saturation is as high as 40%. The large relative permeability reduction in both the water and CO 2 phases is hypothesized to result from the presence of disconnected gas bubbles in this two-phase flow system. This feature
is also thought to be favorable for storage security after CO 2 injection. 相似文献
6.
This article presents a numerical modeling application using the code TOUGHREACT of a leakage scenario occurring during a
CO 2 geological storage performed in the Jurassic Dogger formation in the Paris Basin. This geological formation has been intensively
used for geothermal purposes and is now under consideration as a site for the French national program of reducing greenhouse
gas emissions and CO 2 geological storage. Albian sandstone, situated above the Dogger limestone is a major strategic potable water aquifer; the
impacts of leaking CO 2 due to potential integrity failure have, therefore, to be investigated. The present case–study illustrates both the capacity
and the limitations of numerical tools to address such a critical issue. The physical and chemical processes simulated in
this study have been restricted to: (i) supercritical CO 2 injection and storage within the Dogger reservoir aquifer, (ii) CO 2 upwards migration through the leakage zone represented as a 1D vertical porous medium to simulate the cement–rock formation
interface in the abandoned well, and (iii) impacts on the Albian aquifer water quality in terms of chemical composition and
the mineral phases representative of the porous rock by estimating fluid–rock interactions in both aquifers. Because of CPU
time and memory constraints, approximation and simplification regarding the geometry of the geological structure, the mineralogical
assemblages and the injection period (up to 5 years) have been applied to the system, resulting in limited analysis of the
estimated impacts. The CO 2 migration rate and the quantity of CO 2 arriving as free gas and dissolving, firstly in the storage water and secondly in the water of the overlying aquifer, are
calculated. CO 2 dissolution into the Dogger aquifer induces a pH drop from about 7.3 to 4.9 limited by calcite dissolution buffering. Glauconite
present in the Albian aquifer also dissolves, causing an increase of the silicon and aluminum in solution and triggering the
precipitation of kaolinite and quartz around the intrusion point. A sensitivity analysis of the leakage rate according to
the location of the leaky well and the variability of the petro-physical properties of the reservoir, the leaky well zone
and the Albian aquifers is also provided. 相似文献
7.
We study a sharp-interface mathematical model of CO 2 migration in deep saline aquifers, which accounts for gravity override, capillary trapping, natural groundwater flow, and
the shape of the plume during the injection period. The model leads to a nonlinear advection–diffusion equation, where the
diffusive term is due to buoyancy forces, not physical diffusion. For the case of interest in geological CO 2 storage, in which the mobility ratio is very unfavorable, the mathematical model can be simplified to a hyperbolic equation.
We present a complete analytical solution to the hyperbolic model. The main outcome is a closed-form expression that predicts
the ultimate footprint on the CO 2 plume, and the time scale required for complete trapping. The capillary trapping coefficient and the mobility ratio between
CO 2 and brine emerge as the key parameters in the assessment of CO 2 storage in saline aquifers. Despite the many approximations, the model captures the essence of the flow dynamics and therefore
reflects proper dependencies on the mobility ratio and the capillary trapping coefficient, which are basin-specific. The expressions
derived here have applicability to capacity estimates by capillary trapping at the basin scale. 相似文献
8.
Leakage of CO 2 through fractures in saline formations will increase the CO 2??brine interface and promote CO 2 dissolution. We use a 2D, finite difference MATLAB model to simulate dissolution rates from a vertical fracture, with CO 2 flowing through it, in a secondary storage formation. The instigation of convection currents increases dissolution rates leading to higher dissolution in higher Rayleigh number systems. Comparison of our results with fracture flow rates shows that for typical fracture apertures dissolution from a fracture is small relative to the amount of CO 2 flowing through the fracture. Temporal and spatial variations in fracture permeability may reduce fracture flow rates and increase the relative amount of CO 2 dissolved from the fracture compared to the CO 2 flowing through the fracture. Further work on CO 2 dissolution in relation to fracture heterogeneity, flow of CO 2 within fractures and the interaction of multiple fractures will improve our ability to predict CO 2 dissolution rates for site characterisation. 相似文献
9.
The primary purpose of this study is to understand quantitative characteristics of mobile, residual, and dissolved CO 2 trapping mechanisms within ranges of systematic variations in different geologic and hydrologic parameters. For this purpose,
we conducted an extensive suite of numerical simulations to evaluate the sensitivities included in these parameters. We generated
two-dimensional numerical models representing subsurface porous media with various permutations of vertical and horizontal
permeability ( k
v and k
h), porosity (f{\phi}), maximum residual CO 2 saturation ( Sgrmax{S_{\rm gr}^{\max}}), and brine density ( ρ
br). Simulation results indicate that residual CO 2 trapping increases proportionally to kv, kh, Sgrmax{k_{\rm v}, k_{\rm h}, S_{\rm gr}^{\max}} and ρ
br but is inversely proportional to f.{\phi.} In addition, the amount of dissolution-trapped CO 2 increases with k
v and k
h, but does not vary with f{\phi } , and decreases with Sgrmax{S_{\rm gr}^{\max}} and ρ
br. Additionally, the distance of buoyancy-driven CO 2 migration increases proportionally to k
v and ρ
br only and is inversely proportional to kh, f{k_{\rm h}, \phi } , and Sgrmax{S_{\rm gr}^{\max}} . These complex behaviors occur because the chosen sensitivity parameters perturb the distances of vertical and horizontal
CO 2 plume migration, pore volume size, and fraction of trapped CO 2 in both pores and formation fluids. Finally, in an effort to characterize complex relationships among residual CO 2 trapping and buoyancy-driven CO 2 migration, we quantified three characteristic zones. Zone I, expressing the variations of Sgrmax{S_{\rm gr}^{\max}} and k
h, represents the optimized conditions for geologic CO 2 sequestration. Zone II, showing the variation of f{\phi} , would be preferred for secure CO 2 sequestration since CO 2 has less potential to escape from the target formation. In zone III, both residual CO 2 trapping and buoyancy-driven migration distance increase with k
v and ρ
br. 相似文献
10.
Geologic structures associated with depleted natural gas reservoirs are desirable targets for geologic carbon sequestration
(GCS) as evidenced by numerous pilot and industrial-scale GCS projects in these environments world-wide. One feature of these
GCS targets that may affect injection is the presence of residual CH 4. It is well known that CH 4 drastically alters supercritical CO 2 density and viscosity. Furthermore, residual gas of any kind affects the relative permeability of the liquid and gas phases,
with relative permeability of the gas phase strongly dependent on the time-history of imbibition or drainage, i.e., dependent
on hysteretic relative permeability. In this study, the effects of residual CH 4 on supercritical CO 2 injection were investigated by numerical simulation in an idealized one-dimensional system under three scenarios: (1) with
no residual gas; (2) with residual supercritical CO 2; and (3) with residual CH 4. We further compare results of simulations that use non-hysteretic and hysteretic relative permeability functions. The primary
effect of residual gas is to decrease injectivity by decreasing liquid-phase relative permeability. Secondary effects arise
from injected gas effectively incorporating residual gas and thereby extending the mobile-gas plume relative to cases with
no residual gas. Third-order effects arise from gas mixing and associated compositional effects on density that effectively
create a larger plume per unit mass. Non-hysteretic models of relative permeability can be used to approximate some parts
of the behavior of the system, but fully hysteretic formulations are needed to accurately model the entire system. 相似文献
11.
This article presents a numerical investigation of the combined effects of capillary pressure, salinity and in situ thermodynamic conditions on CO 2-brine-rock interactions in a saline aquifer. We demonstrate that the interrelations between capillary pressure, salinity, dissolution and drying-out affect CO 2 injectivity and storage capacity of a saline aquifer. High capillary forces require a high injection pressure for a given injection rate. Depending on salinity, the increase in injection pressure due to capillary forces can be offset by the dissolution of CO 2 in formation water and its compressibility. Higher capillary forces also reduce gravity segregation, and this gives a more homogeneous CO 2 plume which improves the dissolution of CO 2. The solubility of CO 2 in formation water decreases with increasing salinity which requires an increased injection pressure. Higher salinity and capillary pressure can even block the pores, causing an increased salt precipitation. Simulations with various pressure-temperature conditions and modified salinity and capillary pressure curves demonstrate that, with the injection pressures similar for both cold and warm basins at a given injection rate, CO 2 dissolves about 10% more in the warm basin water than in the cold basin. The increase in dissolution lowers the injection pressure compensating the disadvantage of low CO 2 density and compressibility for storage in warm basins. 相似文献
12.
Simulations of CO 2 injection into confined saline aquifers were conducted for both vertical and horizontal injection wells. The metrics used
in quantifying the performances of different injection scenarios included changes in pressure near the injection well, mass
of CO 2 dissolved into brine (solubility trapping), and storage efficiency, all evaluated with an assumed injection period of 50 years.
Metrics were quantified as functions of well length, well orientation, CO 2 injection rate, and formation anisotropy (ratio of vertical to horizontal conductivity). When equal well lengths are compared,
there is not a significant difference between the predicted performances of horizontal and vertical wells. However, the length
of a horizontal well may exceed the length of a vertical well because the length of the horizontal well is not constrained
to the vertical thickness of the geologic formation. Simulations show that, as the length of the horizontal well is allowed
to increase, the geologic formation can receive a significantly higher CO 2 injection rate without exceeding a maximum allowable pressure. This result is observed in both isotropic and anisotropic
formations, and suggests that horizontal wells may be advantageous under pressure-limited conditions. However, the use of
horizontal wells does not significantly improve the storage efficiency, and under strongly anisotropic conditions, a vertical
well provides higher storage efficiency than a horizontal well. We conclude that horizontal wells may be preferable if the
goal is to sequester a large amount of CO 2 in a short period of time, but do not offer a significant advantage in terms of long-term capacity of a potential repository. 相似文献
13.
The hydrodynamic behavior of carbon dioxide (CO 2) injected into a deep saline formation is investigated, focusing on trapping mechanisms that lead to CO 2 plume stabilization. A numerical model of the subsurface at a proposed power plant with CO 2 capture is developed to simulate a planned pilot test, in which 1,000,000 metric tons of CO 2 is injected over a 4-year period, and the subsequent evolution of the CO 2 plume for hundreds of years. Key measures are plume migration distance and the time evolution of the partitioning of CO 2 between dissolved, immobile free-phase, and mobile free-phase forms. Model results indicate that the injected CO 2 plume is effectively immobilized at 25 years. At that time, 38% of the CO 2 is in dissolved form, 59% is immobile free phase, and 3% is mobile free phase. The plume footprint is roughly elliptical,
and extends much farther up-dip of the injection well than down-dip. The pressure increase extends far beyond the plume footprint,
but the pressure response decreases rapidly with distance from the injection well, and decays rapidly in time once injection
ceases. Sensitivity studies that were carried out to investigate the effect of poorly constrained model parameters permeability,
permeability anisotropy, and residual CO 2 saturation indicate that small changes in properties can have a large impact on plume evolution, causing significant trade-offs
between different trapping mechanisms. 相似文献
14.
During CO 2 injection into brine aquifers-containing residual and/or dissolved CH 4, three distinct regions develop: (1) a single-phase, dry-out region around the well-bore filled with pure supercritical CO 2; (2) a two-phase, two-component system containing CO 2 and brine; and (3) a two-phase, two-component system containing CH 4, and brine. This article extends an existing analytical solution, for pressure buildup during CO 2 injection into brine aquifers, by incorporating dissolved and/or residual CH 4. In this way, the solution additionally accounts for partial miscibility of the CO 2?CCH 4?Cbrine system and the relative permeability hysteresis associated with historic imbibition of brine and current drainage due to CO 2 injection and CH 4 bank development. Comparison of the analytical solution results with commercial simulator, CMG-GEM, shows excellent agreement among a range of different scenarios. The presence of residual CH 4 in a brine aquifer summons two competing phenomena, (1) reduction in relative permeability (phase interference), which increases pressure buildup by reducing total mobility, and (2) increase in bulk compressibility which decreases pressure buildup of the system. If initial CH 4 is dissolved (no free CH 4), these effects are not as important as they are in the residual gas scenario. Relative permeability hysteresis increased the CH 4 bank length (compared to non-hysteretic relative permeability), which led to further reduction in pressure buildup. The nature of relative permeability functions controls whether residual CH 4 is beneficial or disadvantageous to CO 2 storage capacity and injectivity in a candid brine aquifer. 相似文献
15.
Dissolution of CO 2 into brine causes the density of the mixture to increase. The density gradient induces natural convection in the liquid phase,
which is a favorable process of practical interest for CO 2 storage. Correct estimation of the dissolution rate is important because the time scale for dissolution corresponds to the
time scale over which free phase CO 2 has a chance to leak out. However, for this estimation, the challenging simulation on the basis of convection–diffusion equation
must be done. In this study, pseudo-diffusion coefficient is introduced which accounts for the rate of mass transferring by
both convection and diffusion mechanisms. Experimental tests in fluid continuum and porous media were performed to measure
the real rate of dissolution of CO 2 into water during the time. The pseudo diffusion coefficient of CO 2 into water was evaluated by the theory of pressure decay and this coefficient is used as a key parameter to quantify the
natural convection and its effect on mass transfer of CO 2. For each experiment, fraction of ultimate dissolution is calculated from measured pressure data and the results are compared
with predicted values from analytical solution. Measured CO 2 mass transfer rate from experiments are in reasonable agreement with values calculated from diffusion equation performed
on the basis of pseudo-diffusion coefficient. It is suggested that solving diffusion equation with pseudo diffusion coefficient
herein could be used as a simple and rapid tool to calculate the rate of mass transfer of CO 2 in CCS projects. 相似文献
16.
The idea of underground storage of hydrogen exists today in several forms. One of the most promising methods is the option of underground methanation, which consists of injecting H2 and CO2 into an underground porous reservoir (aquifer) and converting them into methane by means of methanogenic bacteria that initiate the methanation reaction. However, due to their activities, the high accumulation of bacteria in the
pore walls causes pore-clogging (microbial-induced clogging); one of the main problems that can become an
obstacle to the implementation of this idea. In this paper, we develop a conceptual model of bio-clogging, which consists of several stages of attachment to pore walls, detachment from the walls and pore plugging by the biomass growth. This model was built into the numerical model of multicomponent two-phase flow. The effect of bio-clogging on gas movement in the storage was analyzed numerically. It has been found that bio-clogging reduces vertical rise of hydrogen and results in more uniform radial gas penetration into the reservoir. 相似文献
17.
Realizable CO2 storage potential for saline formations without closed lateral boundaries depends on the combined effects of physical and chemical trapping mechanisms to prevent long-term migration out of the defined storage area. One such mechanism is the topography of the caprock surface, which may retain CO2 in structural pockets along the migration path. Past theoretical and modeling studies suggest that even traps too small to be accurately described by seismic data may play a significant role. In this study, we use real but scarce seismic data from the Gassum Formation of the Norwegian Continental shelf to estimate the impact of topographical features of the top seal in limiting CO2 migration. We seek to estimate the amount of macro- and sub-scale trapping potential of the formation based on a few dozen interpreted 2D seismic lines and identified faults. We generate multiple high-resolution realizations of the top surface, constructed to be faithful to both large-scale topography and small-scale statistical properties. The structural trapping and plume retardation potential of these top surfaces is subsequently estimated using spill-point (static) analysis and dynamical flow simulation. By applying these techniques on a large ensemble of top surface realizations generated using a combination of stochastic realizations and systematic variation of key model parameters, we explore the range of possible impacts on plume advancement, physical trapping and migration direction. The stochastic analysis of trapping capacity and retardation efficiency in statistically generated, sub-seismic resolution features may also be applied for surfaces generated from 3D data. 相似文献
18.
We apply a multi-component reactive transport lattice Boltzmann model developed in previous studies for modeling the injection
of a CO 2-saturated brine into various porous media structures at temperatures T = 25 and 80°C. In the various cases considered the porous medium consists initially of calcite with varying grain size and
shape. A chemical system consisting of Na +, Ca 2+, Mg 2+, H +, CO 2°(aq){{\rm CO}_2^{\circ}{\rm (aq)}}, and Cl − is considered. Flow and transport by advection and diffusion of aqueous species, combined with homogeneous reactions occurring
in the bulk fluid, as well as the dissolution of calcite and precipitation of dolomite are simulated at the pore scale. The
effects of the structure of the porous media on reactive transport are investigated. The results are compared with a continuum-scale
model and the discrepancies between the pore- and continuum-scale models are discussed. This study sheds some light on the
fundamental physics occurring at the pore scale for reactive transport involved in geologic CO 2 sequestration. 相似文献
19.
We investigated the mechanism of residual gas trapping at a microscopic level. We imaged trapped air bubbles in a Berea sandstone
chip after spontaneous imbibition at atmospheric pressure. The pore structure and trapped bubbles were observed by microfocused
X-ray computed tomography. Distributions of trapped bubbles in Berea and Tako sandstone were imaged in coreflooding at a capillary
number of 1.0 × 10 −6. Trapped bubbles are of two types, those occupying the center of the pore with a pore-scale size and others having a pore-network
scale size. In low-porosity media such as sandstone, connected bubbles contribute greatly to trapped gas saturation. Effects
of capillary number and injected water volume were investigated using a packed bed of glass beads 600μm in diameter, which
had high porosity (38%). The trapped N 2 bubbles are stable against the water flow rate corresponding to a capillary number of 1.0 × 10 −4. 相似文献
20.
This paper deals with the problem of disposal of industrial waste greenhouse gases (CO 2) into deep reservoirs. The simulator TOUGH2 was used to model the injection of 100 kg/s of CO 2 for 10 years into an aquifer 3 km deep with the object of evaluating the long-term storage prospects for this gas. Depending on the permeability structure above the injection point, some gas may escape to the surface. In the most favourable case, all of the gas dissolves into the water, and the resulting dense fluid settles in the aquifer over several thousand years. Consequently, underground storage provides a promising sink for reducing CO 2 emissions to the atmosphere. 相似文献
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