CO2 Sequestration In Aquifers Research Articles

Effects of Pore Geometry and Saturation on the Behavior of Multiscale Waves in Tight Sandstone Layers

AbstractGeometric heterogeneities in tight reservoir rocks saturated with a fluid mixture may exhibit different scale distribution characteristics. Conventional models of rock physics based on poroelasticity, which usually consider single‐scale pore structure and fluid patches, are inadequate for describing elastic wave responses. A major challenge is to establish the relationship between the wave response at different spatial scales and frequencies. To address this problem, three sets of observational data over a wide frequency range were obtained from a tight oil reservoir in the Ordos Basin, China. Ultrasonic measurements were made on eight sandstone samples at partial oil‐water saturation at 0.55 MHz. Data from six borehole measurements and seismic profiles were acquired and analyzed at about 10 kHz and 30 Hz, respectively. Analysis of the cast thin sections shows that dissolution pores and microcracks generally develop, with fractal dimensions of the pores ranging from 2.45 to 2.67 for the samples with porosities between 5.1% and 10.2%. Compressional wave velocity and attenuation were estimated from the observed data. The results show that the velocity dispersion from seismic to ultrasonic frequencies is 10.02%, mostly occurring between sonic and ultrasonic frequencies. The attenuation is stronger at higher oil saturation. The relationships between velocity, attenuation, and wavelength were established and can be used for further forward modeling and seismic interpretation studies. A partial saturation model has been derived based on effective differential medium theory and a double double‐porosity model, assuming that the medium contains fractal cracks and fluid patches. The effects of scale and saturation on wave responses are prevalent. Modeling results consistent with observed data show that the radii of cracks and fluid patches range from 0.1 μm to 2.8 mm, affecting ultrasonic, acoustic, and seismic attenuation. The multiscale data and proposed model quantify the relationship between fracture and fluid distributions and attenuation and could be useful for upscaling to the reservoir scale. The study helps improve the understanding of seismic wave propagation in partially saturated rocks, which has potential applications in seismic exploration, hydrocarbon production in reservoirs, and CO2 sequestration in aquifers.

Isothermal CO2 injection into water-saturated porous media: Lattice-Boltzmann modelling of pulsatile flow with porosity, tortuosity, and optimal frequency characterization

The Lattice Boltzmann Method (LBM) is used to simulate the isothermal injection of CO2 into a water-saturated, homogeneous porous medium. The complex multiphase flow is modeled using the 2D-pseudopotential Shan-Chen multiphase LBM. This work proposes a unique fluid-pulse technology similar to the one applied to enhance oil recovery with CO2 sequestration. This technology is different from classical CO2 sequestration in aquifers and, to our knowledge, has never been used before. The primary purpose is to investigate whether our LBM simulation allows the introduction of fluid-pulse CO2 injection patterns similar to those reported in the literature on hydrocarbon reservoirs and to evaluate the benefit of using such a technique compared to classical uniform injection. First, our simulations consider a transient homogeneous flow with uniform inlet velocity to determine the natural frequency of the instabilities triggered downstream of the interstitial pore array. Then, CO2 is injected at the inlet in a pulsating regime, varying the forcing frequency near and far from the natural frequency to determine its effect on CO2 penetration. Results demonstrate that a pulsatile injection effectively enhances CO2 sequestration in aquifers when forced with a characteristic frequency. However, this frequency resulting after CO2 is injected to displace the water differed from the natural frequency preliminarily obtained from the homogeneous water flow. Injecting at the characteristic frequency has proven an effective technique for boosting CO2 penetration into a water-saturated porous medium, with a significant enhancement estimated between 1.5% and 16% for a range of pulsatile amplitudes between 1% and 10%.

Study on influence factors of saline aquifer CO2 sequestration under the constraint of cap rock

In view of the practical problems faced by the CO2 sequestration in aquifers, this paper considers the influence of injection rate, water production rate, and other factors on CO2 injection amount, residual sequestration amount, dissolution sequestration amount, and pressure evolution under the constraint of cap rock breakthrough pressure is studied by using a numerical simulation method, and the sequestration potential is evaluated. The results show that: (1) Water production measures can improve CO2 injection, dissolution sequestration, and residual sequestration. (2) Low ratio of vertical permeability to horizontal permeability is conducive to the security and stability of CO2 sequestration in the long term. The research content provides support for the evaluation of CO2 saline aquifer sequestration potential and field practice.

Modeling Immiscible Fluid Displacement in a Porous Medium Using Lattice Boltzmann Method

The numerical investigation of the interpenetrating flow dynamics of a gas injected into a homogeneous porous media saturated with liquid is presented. The analysis is undertaken as a function of the inlet velocity, liquid–gas viscosity ratio (D) and physical properties of the porous medium, such as porous geometry and surface wettability. The study aims to improve understanding of the interaction between the physical parameters involved in complex multiphase flow in porous media (e.g., CO2 sequestration in aquifers). The numerical simulation of a gaseous phase being introduced through a 2D porous medium constructed using seven staggered columns of either circular- or square-shaped micro-obstacles mimicking the solid walls of the pores is performed using the multiphase Lattice Boltzmann Method (LBM). The gas–liquid fingering phenomenon is triggered by a small geometrical asymmetry deliberately introduced in the first column of obstacles. Our study shows that the amount of gas penetration into the porous medium depends on surface wettability and on a set of parameters such as capillary number (Ca), liquid–gas viscosity ratio (D), pore geometry and surface wettability. The results demonstrate that increasing the capillary number and the surface wettability leads to an increase in the effective gas penetration rate, disregarding porous medium configuration, while increasing the viscosity ratio decreases the penetration rate, again disregarding porous medium configuration.

Pore-scale study based on lattice Boltzmann method of density driven natural convection during CO2 injection project

Saline aquifers are chosen for geological storage of greenhouse gas CO2 because of their storage potential. In almost all cases of practical interest, CO2 is present on top of the liquid and CO2 dissolution leads to a small increase in the density of the aqueous phase. This situation results in the creation of negative buoyancy force for downward density-driven natural convection and consequently enhances CO2 sequestration. In order to study CO2 injection at pore-level, an isothermal Lattice Boltzmann Model (LBM) with two distribution functions is adopted to simulate density-driven natural convection in porous media with irregular geometry obtained by image treatment. The present analysis showed that after the onset of natural convection instability, the brine with a high CO2 concentration infringed into the underlying unaffected brine, in favor of the migration of CO2 into the pore structure. With low Rayleigh numbers, the instantaneous mass flux and total dissolved CO2 mass are very close to that derived from penetration theory (diffusion only), but the fluxes are significantly enhanced with high Ra number. The simulated results show that as the time increases, some chaotic and recirculation zones in the flow appear obviously, which promotes the renewal of interfacial liquid, and hence enhances dissolution of CO2 into brine. This study is focused on the scale of a few pores, but shows implications in enhanced oil/gas recovery with CO2 sequestration in aquifers.

Design of foam-assisted carbon dioxide storage in a North Sea aquifer using streamline-based simulation

Carbon capture and storage (CCS) – the collection of CO2 from industrial sources and its injection underground – could potentially contribute to the reduction of atmospheric emissions of greenhouse gases. In this paper, we investigate the sequestration of CO2 in aquifers with the co-injection of surfactants for foam generation. This is equivalent to the use of foam for conformance control in enhanced oil recovery applications. To study foam-assisted sequestration, we extend an in-house streamline-based simulator to model foam flow. We use two foam models that have been previously suggested in the literature. In both models foam hinders gas mobility through increasing its apparent viscosity. The modified simulator is validated by comparison to analytical solutions. We then investigate the performance of CO2 sequestration with the co-injection of surfactants. We look at CO2 sequestration in a North Sea aquifer. We study both simultaneous and alternating surfactant-gas injection at different fractional flows (i.e. water:gas ratios). For cases where a seal provides a reliable trapping mechanism, the simulation results suggest that the use of surfactants to generate foam significantly improves the storage efficiency at a marginal increase in water consumption. In this setting, CO2/surfactant simultaneous injection at a 0.5 CO2 fractional flow was found to be the optimum injection strategy for the case investigated. To the contrary, if the seal is unreliable or not present at the first place, CO2/brine simultaneous injection at a 0.85 CO2 fractional flow was found to be the optimum injection strategy. Although foam-assisted sequestration in this case further improves the storage efficiency, it does that at a significant increase in water consumption. This is since, although foam generation improves the sweep during the sequestration phase, it significantly hinders the sweep during the chase-brine injection phase. Based on that, having a design where the surfactant will degrade just before or during the chase-brine injection phase would provide the optimum sequestration strategy—without reliance on the presence or integrity of the seal.

Assessment of the recovery and front contrast of CO2 EOR and sequestration in a new gas condensate reservoir by compositional simulation and seismic modeling

While mature oil reservoirs and aquifers are considered to be good potential candidates for CO2 sequestration, we proposed and investigated an alternative which combines CO2 sequestration and CO2 EOR at the very start of production in a gas condensate reservoir. First, we established a co-simulation workflow with a combination of compositional reservoir simulation and synthetic seismic simulation. Next, we conducted compositional reservoir simulation and synthetic seismic simulation in a five-spot well pattern to investigate whether seismic data can monitor the CO2 front and gas condensate bank with CO2 injected from the very beginning of well production. Then, we compared the compositional simulation results with the seismic simulation results. Although the density contrast among reservoir gas, injected CO2, and condensate is lower than the density contrast in the case of CO2 sequestration in aquifers, the seismic signal may have the potential to capture this smaller difference, monitor the CO2 injection front, and locate the condensate zone, depending on the temperature, pressure and phase properties. When no adequate data are available for reservoir characterization at an early period of production, the seismic data is the only direct measurement of inter-well properties. It may be very valuable for reservoir characterization and for the evaluation of the condensate block. It can serve as the basis for time-lapse monitoring. We compare production by natural depletion with production by CO2 EOR and sequestration started at the very beginning of well production. It shows that the latter will speed up the recovery process and increase the recovery rate while simultaneously storing a large amount of CO2 in the reservoir.

Temperature influence on permeability of Sioux quartzite containing mixtures of water and carbon dioxide

CO2 sequestration in aquifers and depleted hydrocarbon reservoirs is a promising option for reducing atmospheric CO2. However, its implementation requires understanding how CO2 propagates and how it is stored in the reservoir. CO2 mixed with water exists in two forms, an immiscible phase (gas or liquid depending on the conditions of temperature and pressure) and a dissolved phase (a minor part of which reacts with H2O to form carbonic acid, H2CO3). The motion of CO2 in the reservoir is therefore a two-phase flow problem. Fluid/rock chemical reactions may also be important, but they are not considered here. When several immiscible fluids occupy the pore space, each phase may act as an obstacle to the motion of the others. Indeed, experimental evidence from oil production, vadose zone or CO2 sequestration studies [1] demonstrates that permeability is affected by the presence of a second phase in the pore space. The motion and spatial distribution of pore fluids (like water and carbon dioxide) are controlled not only by pore geometry and fluid pressure, but also by the viscosity, solubility, surface tension and wetting characteristics of each fluid phase [2], properties that usually vary with temperature. In the case of carbon dioxide and water, the solubility of CO2 is particularly sensitive to temperature. Thus, temperature variations may also affect the distribution and flow of the phases in the pore space. In this work, we measured the effect of temperature variations on the permeability of a rock saturated with a mixture of carbon dioxide and water. We used the oscillating pore pressure method (OPPM) developed by Kranz et al. [3] and Fischer et al. [4], because it minimizes fluid flux and, therefore, is not expected to disturb the phase distribution in the pore space as much as a steadily flowing fluid would. Although the method was devised to measure permeability of rocks with a single fluid phase, we can assess the effect of the second phase by comparing the permeability measurements made using a single fluid to those with a two-phase mixture.

Influence of capillary-pressure models on CO2 solubility trapping

The typical shape of a capillary-pressure curve is either convex (e.g., Brooks–Corey model) or S-shaped (e.g., van Genuchten model). It is not universally agreed which model reflects natural rocks better. The difference between the two models lies in the representation of the capillary entry pressure. This difference does not lead to significantly different simulation results for modeling CO2 sequestration in aquifers without considering CO2 dissolution. However, we observe that the van-Genuchten-type capillary-pressure model accelerates CO2 solubility trapping significantly compared with the Brooks–Corey-type model. We also show that the simulation results are very sensitive to the slope of the van-Genuchten-type curve around the entry-pressure region. For the representative examples we study, the differences can be so large as to have complete dissolution of the CO2 plume versus persistence of over 50% of the plume over a 5000-year period.The cause of such sensitivity to the capillary-pressure model is studied. Particularly, we focus on how the entry pressure is represented in each model. We examine the mass-transfer processes under gravity-capillary equilibrium, molecular diffusion, convective mixing, and in the presence of small-scale heterogeneities. Laboratory measurement of capillary-pressure curves and some important implementation issues of capillary-pressure models in numerical simulators are also discussed. Most CO2 sequestration simulations in the literature employ one of the two capillary-pressure models. It is important to recognize that these two representations lead to very different predictions of long-term CO2 sequestration.

A numerical procedure to model and monitor CO2 sequestration in aquifers

Carbon Dioxide (CO2) sequestration into geologic formations is a means of mitigating greenhouse effect. In this work we present a new numerical simulation technique to model and monitor CO2 sequestration in aquifers. For that purpose we integrate numerical simulators of CO2-brine flow and seismic wave propagation (time-lapse seismics). The simultaneous flow of brine and CO2 is modeled applying the Black-Oil formulation for two phase flow in porous media, which uses the Pressure-Volume-Temperature (PVT) behavior as a simplified thermodynamic model. Seismic wave propagation uses a simulator based on a space-frequency domain formulation of the viscoelastic wave equation. In this formulation, the complex and frequency dependent coefficients represent the attenuation and dispersion effect suffered by seismic waves travelling in fluid-saturated heterogeneous porous formations. The spatial discretization is achieved employing a nonconforming finite element space to represent the displacement vector. Numerical examples of CO2 injection and time-lapse seismics in the Utsira formation at the Sleipner field are analyzed. The Utsira formation is represented using a new petrophysical model that allows a realistic inclusion of shale seals and fractures. The results of the simulations show the capability of the proposed methodology to monitor the spatial distribution of CO2 after injection.

Three‐phase compositional modeling of CO2 injection by higher‐order finite element methods with CPA equation of state for aqueous phase

Most simulators for subsurface flow of water, gas, and oil phases use empirical correlations, such as Henry's law, for the CO2 composition in the aqueous phase, and equations of state (EOS) that do not represent the polar interactions between CO2and water. Widely used simulators are also based on lowest‐order finite difference methods and suffer from numerical dispersion and grid sensitivity. They may not capture the viscous and gravitational fingering that can negatively affect hydrocarbon (HC) recovery, or aid carbon sequestration in aquifers. We present a three‐phase compositional model based on higher‐order finite element methods and incorporate rigorous and efficient three‐phase‐split computations for either three HC phases or water‐oil‐gas systems. For HC phases, we use the Peng‐Robinson EOS. We allow solubility of CO2in water and adopt a new cubic‐plus‐association (CPA) EOS, which accounts for cross association between H2O and CO2 molecules, and association between H2O molecules. The CPA‐EOS is highly accurate over a broad range of pressures and temperatures. The main novelty of this work is the formulation of a reservoir simulator with new EOS‐based unique three‐phase‐split computations, which satisfy both the equalities of fugacities in all three phases and the global minimum of Gibbs free energy. We provide five examples that demonstrate twice the convergence rate of our method compared with a finite difference approach, and compare with experimental data and other simulators. The examples consider gravitational fingering during CO2sequestration in aquifers, viscous fingering in water‐alternating‐gas injection, and full compositional modeling of three HC phases.

Diffusive and Convective Mechanisms during CO2 Sequestration in Aquifers

CO2 emissions originated from industrial sources can be captured, transported, and stored in depleted gas/oil fields and deep saline aquifers. The transport mechanisms, occurred during CO2 sequestration in deep saline aquifers, are examined in this study. After injecting CO2 until the tolerable pressure for the aquifer is reached, the wells are closed and CO2 is deposited as free gas and soluble gas in water under the sealing rock. During injection and waiting periods, the concentration profile of CO2 within the aquifer is formed by diffusion and convection mechanisms. The Rayleigh number and mixing zone length concepts are used for investigating the effect of reservoir properties, such as dispersivity, permeability, porosity, and others on the aforementioned mechanisms. The results of convective dominant mechanism in aquifers with 1 md and 10 md permeability values are so near in that diffusion-dominated system. After 10 md, the convection mechanism begins to dominate gradually and it becomes totally convection dominated for 50 md and higher permeability values. These results are also verified by the Rayleigh number and mixing zone lengths.