CO<Subscript>2</Subscript> injection into saline carbonate aquifer formations I: laboratory investigation

Although there are a number of mathematical modeling studies for carbon dioxide (CO₂) injection into aquifer formations, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to analyze permeability and porosity changes as well as to characterize relevant chemical reactions associated with injection and storage of CO₂ in carbonate formations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. Highly heterogeneous cores drilled from a carbonate aquifer formation located in South East Turkey were used during the experiments. Porosity changes along the core plugs and the corresponding permeability changes are reported for different CO₂ injection rates and different salt concentrations of formation water. It was observed that either a permeability increase or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related to distribution of pores, brine composition and thermodynamic conditions. As the salt concentration decreases, porosity and the permeability decreases are less pronounced. Calcite deposition is mainly influenced by orientation, with horizontal flow resulting in larger calcite deposition compared to vertical flow.     

Construction of Dual Pore 3-D Digital Cores with a Hybrid Method Combined with Physical Experiment Method and Numerical Reconstruction Method

In order to further improve the accuracy of digital core modeling, a new hybrid method was proposed to construct the dual pore 3-D digital core with high precision. First of all, 3-D macro-pore digital cores were constructed by micro-CT. Secondly, based on the high-resolution 2-D scanning electron microscopy images of rock cores, micro-pore digital cores were constructed by simulated annealing method. And then, a superposition method was used to construct the digital core which could describe different pore characteristics. Finally, pore structures of digital cores were compared, and lattice Boltzmann method was used to analyze the percolation properties. The results show that the carbonate dual pore digital core constructed by the new hybrid method has a high accuracy, which can capture the pore properties of both macro-pore and micro-pore, and whose permeability simulation results are in good agreement with the experimental measurements. In addition, the new hybrid method is not only accurate and reliable, but also high efficient and economic, and can be applied to all kinds of reservoir modeling.     

Spontaneous Switching between Permeability Enhancement and Degradation in Fractures in Carbonate: Lumped Parameter Representation of Mechanically- and Chemically-Mediated Dissolution

Principal mechanical and chemical processes contributing to the observed spontaneous switching from net decrease in permeability to net increase in a fracture in carbonate are examined. The evolution of permeability, and related fracture aperture, is represented through a lumped parameter model. The significant processes of pressure solution beneath bridging asperities, transport of dissolved mass to the fracture void, and subsequent precipitation or dissolution within the fracture void enable the principal characteristics of observed behavior to be followed. The evolution of dissolved mass concentration in the pore fluid is followed for arbitrary applied stress, temperature, and pH conditions, with appropriate feedback to the evolution of fracture permeability. Comparisons with experimental measurements in limestone (Polak et al., 2004, Water Resour. Res. Vol. 40, W03502, doi: 10.1029/2003GL017575) show satisfactory agreement for the evolution of fracture aperture and to a lesser degree in calcium concentrations in the effluent pore fluid. Importantly, the spontaneous switching in permeability change, from aperture reducing to aperture increasing, with no change in environmental conditions, is replicated without the need for an ad hoc trigger. Although this switch is accurately replicated, the lumped parameter model is incapable of replicating the rapid observed growth in permeability that directly follows. This inability results from the assumed form of the lumped asperity model, that is incapable of representing the spatially distributed change in aperture that is seen to occur within the fracture. Despite this inconsistency, the model is shown capable of representing the principal behaviors evident in the response.     

Laboratory Investigation of LNAPL Migration in Double-Porosity Soil Under Fractured Condition Using Digital Image Analysis

Gas production from shale gas reservoirs plays a significant role in satisfying increasing energy demands. Compared with conventional sandstone and carbonate reservoirs, shale gas reservoirs are characterized by extremely low porosity, ultra-low permeability and high clay content. Slip flow, diffusion, adsorption and desorption are the primary gas transport processes in shale matrix, while Darcy flow is restricted to fractures. Understanding methane diffusion and adsorption, and gas flow and equilibrium in the low-permeability matrix of shale is crucial for shale formation evaluation and for predicting gas production. Modeling of diffusion in low-permeability shale rocks requires use of the Dusty gas model (DGM) rather than Fick’s law. The DGM is incorporated in the TOUGH2 module EOS7C-ECBM, a modified version of EOS7C that simulates multicomponent gas mixture transport in porous media. Also included in EOS7C-ECBM is the extended Langmuir model for adsorption and desorption of gases. In this study, a column shale model was constructed to simulate methane diffusion and adsorption through shale rocks. The process of binary \(\hbox {CH}_{4}{-}\hbox {N}_{2}\) diffusion and adsorption was analyzed. A sensitivity study was performed to investigate the effects of pressure, temperature and permeability on diffusion and adsorption in shale rocks. The results show that methane gas diffusion and adsorption in shale is a slow process of dynamic equilibrium, which can be illustrated by the slope of a curve in \(\hbox {CH}_{4}\) mass variation. The amount of adsorption increases with the pressure increase at the low pressure, and the mass change by gas diffusion will decrease due to the decrease in the compressibility factor of the gas. With the elevated temperature, the gas molecules move faster and then the greater gas diffusion rates make the process duration shorter. The gas diffusion rate decreases with the permeability decrease, and there is a limit of gas diffusion if the permeability is less than \(1.0\,\times \,10^{-15}\, \hbox { m}^{2}\). The results can provide insights for a better understanding of methane diffusion and adsorption in the shale rocks so as to optimize gas production performance of shale gas reservoirs.     

基于规则网络的碳酸盐岩多尺度网络模型构建方法研究

碳酸盐岩油藏非均质性强,孔隙大小变化可达好几个数量级,描述碳酸盐岩油藏多尺度孔隙特征具有重要意义.本文首先基于三维规则网络模型建立了不同物理尺寸的溶洞网络、大孔隙网络和微孔隙网络;然后提出一种耦合算法,以溶洞网络为基础,通过添加适当比例的大孔隙和微孔隙,构建出碳酸盐岩多尺度网络模型;最后对比分析了各网络模型的几何性质、拓扑性质和绝对渗透率.结果表明,碳酸盐岩多尺度网络模型能够同时描述不同尺度孔隙的几何和拓扑特征;且相比各单一尺度的孔隙网络模型,多尺度网络模型有着较高的绝对渗透率,这是由于各尺度孔隙之间的相互连通极大地提高了网络的整体连通性和流动能力,为碳酸盐岩油藏微观渗流模拟提供了重要的研究平台.     

页岩有机质纳米孔隙气体吸附与流动规律研究

页岩储层孔隙结构复杂, 气体赋存方式多样. 有机质孔隙形状对受限空间气体吸附和流动规律的影响尚不明确, 导致难以准确认识页岩气藏气体渗流机理. 为解决该问题, 本文首先采用巨正则蒙特卡洛方法模拟气体在不同形状有机质孔隙(圆形孔隙、狭长孔隙、三角形孔隙、方形孔隙)内吸附过程, 发现不同形状孔隙内吸附规律符合朗格缪尔单层吸附规律, 分析了绝对吸附量、过剩吸附浓量、气体吸附参数随孔隙尺寸、压力的变化, 研究了孔隙形状对气体吸附的影响. 在明确不同形状有机质孔隙内气体热力学吸附规律基础上, 建立不同形状有机质孔隙内吸附气表面扩散数学模型和考虑滑脱效应的自由气流动数学模型, 结合分子吸附模拟结果研究了不同孔隙形状、孔隙尺寸有机质孔隙内吸附气流动与自由气流动对气体渗透率的贡献. 结果表明, 狭长孔隙内最大吸附浓度和朗格缪尔压力最高, 吸附气表面扩散能力最弱. 孔隙半径5 nm以上时, 吸附气表面扩散对气体渗透率影响可忽略. 本文研究揭示了页岩气藏实际生产过程中有机质孔隙形状对页岩气吸附和流动能力的影响机制.      

The Constitute Law of Gas Seepage in Rock Fractures Undergoing Three-dimensional Stress

This paper is based on the research we have done in recent years of the constitute law of gas seepage in rock fractures. Both experiments and theoretical derivations will be discussed. The gases used in our experiments include methane and CO₂, both of which are highly adsorptive. The experiments were conducted mainly in coal fractures. The results reveal that the permeability coefficient of gas in rock fractures varies parabolically with respect to fracture pore pressure. When the pore pressure is below a certain value, the permeability coefficient decreases while the pore pressure increases. It is different from the water seepage law in fractures. Analysis shows that this abnormality is caused by adsorption. It is also concluded that the tangent deformation has the same effects as normal deformation on gas seepage law. The permeability of gas in fractures has a negative exponent relationship with both normal deformation and tangent deformation.     

A Semi-analytical Model for Pressure-Dependent Permeability of Tight Sandstone Reservoirs

In tight gas reservoirs, permeability is pressure dependent owing to pore pressure reduction during the life of the reservoir. Empirical models are commonly used to describe pressure-dependent permeability. In this paper, it was discussed a number of issues which centered around tight sandstone pressure-dependent permeability experiment, first to apply core aging on permeability test and then to develop a new semi-analytical model to predict permeability. In tight sandstone permeability test experiment, the microinterstice between core and sleeves resulted in over estimation of dependency of permeability on pressure. Then, a new semi-analytical model was developed to identify the relation between permeability and fluid pressure in tight sandstone, which indicates there is a linear relation between pore pressure changes and the inverse of permeability to a constant power. Pressure-dependent permeability of 8 tight sandstone core samples from Ordos Basin, China, was obtained using the modified procedure, and results were perfectly matched with the proposed model. Meanwhile, the semi-analytical model was also verified by pressure-dependent permeability of 16 cores in the literature and experiment results of these 24 cores were matched by empirical models and the semi-analytical model. Compared with regression result of commonly used empirical models, the semi-analytical model outperforms the current empirical models on 8 cores from our experiment and 16 cores from the literature. The model verification also indicates that the semi-theoretical model can match the pressure-dependent permeability of different rock types. In addition, the permeability performance under reservoir condition is discussed, which is divided into two stages. In most tight gas reservoirs, the permeability performance during production is located in stage II. The evaluation result with proposed experiment procedure and the stress condition in stage II will reduce permeability sensitivity to stress.     

CO2 Injection into Saline Carbonate Aquifer Formations II: Comparison of Numerical Simulations to Experiments

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 CO₂ storage in saline aquifers. STARS models physical phenomena including (1) thermodynamics of sub- and supercritical CO₂, and PVT properties of mixtures of CO₂ with other fluids, including (saline) water; (2) fluid mechanics of single and multiphase flow when CO₂ is injected into aquifers; (3) coupled hydrochemical effects due to interactions between CO₂, 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 CO₂ 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 CO₂ that showed the migration of CO₂ and the dissociation of CO₂ into HCO₃ and its subsequent conversion into carbonate minerals were considered. It was observed that solubility and hydrodynamic storage of CO₂ is larger compared to mineral trapping.     

Mass-loss effects on the flow behavior in broken argillaceous red sandstone with different particle-size distributions

Under the action of corrosion, abrasion and erosion of surface water and groundwater, the fine rock particles migrate with water and are gradually lose mass, which seriously deteriorates the internal structure of rock mass, causing seepage disasters. It is important to study the effect of mass loss on the seepage property of a broken rock to understand its engineering behavior. Consequently, an experimental system for testing the seepage property of broken rock under the condition of mass loss was designed, and it also could provide the variations of mass loss and porosity. A genetic algorithm of non-Darcy flow was constructed to characterize the seepage properties of broken rock. The effects of mass conservation and mass loss on the seepage properties of broken rock with different Talbot gradation indices were discussed. The results showed that the migration of fine particles in the internal structure of broken rock caused the fluctuations of permeability parameters even in the case of mass conservation. Under the condition of mass loss, the pore structure and framework structure of broken rock were damaged by the gradual loss of rock particles, which resulted in the gradual variation in the seepage property of broken rock. The broken rock specimen with smaller Talbot gradation index lost more easily rock particles. And the permeability of the broken rock specimen under mass loss was negatively correlated with the Talbot gradation index. It indicated that the broken rock with the finer particles caused more easily an unstable structure.     

A New Cleat Volume Compressibility Determination Method and Corresponding Modification to Coal Permeability Model

Coal is known as a dual-porosity media composed of cleat and matrix pore. Methane can be stored in the cleats or adsorbed on the inner surface of matrix pore. While fluid mobility is mainly controlled by the developed cleat network, methane desorption has a significant effect on cleat deformation. In the process of coalbed methane recovery, both reservoir compaction and matrix shrinkage will occur and have opposite effects on permeability evolutions. A variety of analytical permeability models have been developed to describe the transient characteristics of permeability in coals. In this study, three common permeability models are first revisited and evaluated against the experimental data under uniaxial strain condition. Shi–Durucan (S&D) model demonstrates the best performance among these models. However, constant cleat volume compressibility was used to assume for S&D model, and the generalization of S&D model is significantly limited. For ease of generalization, the relation between cleat volume compressibility and effective horizontal stress is re-derived and introduced to the derivation of permeability model. Since coal reservoirs usually demonstrate strong anisotropy and heterogeneity, the influences of elastic and adsorption properties are further tested to reveal the overall trend of permeability. The results show that S&D model and its modification with the main variable of effective horizontal stress have the best performances in matching the experimental data under uniaxial strain. The relationship between cleat volume compressibility and effective horizontal stress can be better reflected by the inverse proportional function. In addition, the strengths of reservoir compaction effect relative to matrix shrinkage effect in different models only vary with Poisson’s ratio, while their magnitudes are also affected by Young’s modulus. For a typical coal reservoir, the C&B and P&M models will observe a stronger permeability decline at the initial, while the improved P&M model will receive an earlier and more rapid rebound than the S&D and W&Z models.     

Prediction of Gas Permeability of Multilayer Woven Reinforcements for SiCf/SiC Porous Composites

The permeability is a key property of SiC_f/SiC porous composites using as filter in high temperature. In this study, an analytical model based on Hagen–Poiseuille flow was used to investigate the relationship between the structural properties and the filtration performance of the fiber architecture, including fabric and stitched preform. The air flow through the fabric was considered in two different regions: inter-yarn and inter-fiber, as well as the pore properties of the fabrics. The key feature of the model was that the parameter of flow channel based on the pore shape was taken account into the calculation of the equivalent pore size. After determining the pore characteristics, the flow rates of the pore unit cell were obtained; subsequently, permeability of the fabrics and stitched preforms were predicted to compare with the experimental ones. This turns out that the analytical model shows a good correlation between the experimental and predicted permeability values, and the difference between different woven-type fabrics was well presented.

     

Use of a gamma ray attenuation technique to study colloid deposition in porous media

An experimental study of colloidal deposition in porous media is presented. The local deposition is determined through a local measurement of porosity variation using a -ray attenuation technique. The basic principle of this technique is described and the accuracy measurement is discussed. An experimental setup was designed using an artificial porous medium flushed with several pore volumes of a latex suspension. The damage to the porous medium was determined from permeability reduction and porosity measurements. A good agreement was obtained for a monolayer deposit. The discrepancy between global and local measurements of multilayer deposition is discussed.     

Two-Phase Flow Properties Prediction from Small-Scale Data Using Pore-Network Modeling

The objective of this work is to evaluate the prediction accuracy of network modeling to calculate transport properties of porous media based on the interpretation of mercury invasion capillary pressure curves only. A pore-scale modeling approach is used to model the multi-phase flow and calculate gas/oil relative permeability curves. The characteristics of the 3-D pore-network are defined with the requirement that the network model satisfactorily reproduces the capillary pressure curve (P_c curve), the porosity and the permeability. A sensitivity study on the effect of the input parameters on the prediction of capillary pressure and gas/oil relative permeability curves is presented. The simulations show that different input parameters can lead to similarly good reproductions of the experimental P_c, although the predicted relative permeabilities K_r are somewhat widespread. This means that the information derived from a mercury invasion P_c curve is not sufficient to characterize transport properties of a porous medium. The simulations indicate that more quantitative information on the wall roughness and the node/bond aspect ratio would be necessary to better constrain the problem. There is also evidence that in narrow pore size distributions pore body volume and pore throat radius are correlated while in broad pore size distributions they would be uncorrelated.     

Understanding Oil and Gas Flow Mechanisms in Shale Reservoirs Using SLD–PR Transport Model

More and more attention has been paid to the oil and gas flow mechanisms in shale reservoirs. The solid–fluid interaction becomes significant when the pores are in the nanoscale. The interaction changes the fluid’s physical properties and leads to different flow mechanisms in shale reservoirs from those in conventional reservoirs. By using a Simplified Local Density–Peng Robinson transport model, we consider the density and viscosity profiles, which result from solid–fluid interaction. Gas rarefaction effect is negligible at high pressure, so we assume it is viscous flow. Considering the density- and viscosity-changing effects, we proposed a slit permeability model. The velocity profiles are obtained by this newly established model. This proposed model is validated by matching the density profile and velocity profile from molecular dynamic simulation. Then, the effects of pressure and pore size on gas and oil flow mechanisms are also studied in this work. The results show that both gas and oil exhibit enhanced flow rates in nanopores. Gas-phase flow in nanopores is dominated by the density-changing effect (adsorption), while the oil-phase flow is mainly controlled by the viscosity-changing effect. Both gas and oil permeability quickly decrease to the Darcy permeability when the slit aperture becomes large. The results reported in this work are representative and should significantly help us understand the mechanisms of oil and gas flow in shale reservoirs.     

A Mechanistic Model of Gas-Condensate Flow in Pores

Recent experimental results reported in the literature indicate that the relative permeability of gas-condensate systems increases with rate (velocity) at some conditions. To gain a better understanding of the nature of the flow and the prevailing mechanisms resulting in such behaviour flow visualisation experiments have been performed, using high pressure micromodels. The observed flow behaviour at the pore level has been employed to develop a mechanistic model describing the coupled flow of gas and condensate phases. The results of the model simulating the observed simultaneous flow of gas and condensate phases have been compared with reported core experimental results. Most features of the reported rate effect are predictable by the developed single pore model, nevertheless, its extension to include multiple pore interaction is recommended.     

The Effect of Asphalt Precipitation on Flow Behavior and Production of a Fractured Carbonate Oil Reservoir During Gas Injection

The first field data, collected over an 11 year period, are presented which indicate the possible effect of asphalt precipitation on the permeability and injectivity index of a fractured carbonate oil reservoir. The asphalt aggregates were formed during enhanced oil recovery by injection of a rich gas into the reservoir. The data indicate that, while at the initial stages of the operations the permeability and injectivity index decrease, at later times they appear to oscillate with the process time, with apparent oscillations' periods that depend on the heterogeneity of the reservoir. Two classes of plausible mechanisms that give rise to such oscillatory behavior are discussed. One relies on the changes in the structure of the reservoir's fractures, while the other one is based on asphalt precipitation in the reservoir. Computer simulations of flow and precipitation of asphalt aggregates in a pore network model of the reservoir are carried out. The results appear to support our proposition that asphalt formation and precipitation in the reservoir are the main mechanism for the observed behavior of the injectivity index. We also develop a stochastic continuum model that accurately predicts the time-dependence of the reservoir's permeability and injectivity index during the gas injection process.     

基于核磁共振技术的非均质岩心中泡沫动态稳定性评价方法及应用

基于有效孔隙体积守恒和核磁共振技术建立了泡沫在岩心中的动态稳定性的评价方法. 利用油、水标定方法测量了岩心中油相和泡沫液的体积, 计算了泡沫在岩心驱替过程中的动态稳定因子. 测试了双层非均质岩心的横向弛豫谱线及核磁共振图像, 比较了纳米颗粒强化泡沫和表面活性剂泡沫的驱油效果和动态稳定因子. 结果表明, 岩心中的含水体积在注入2.0 PV泡沫前快速上升随后基本稳定; 而含气体积逐渐上升, 注入5.0 PV泡沫后上升速率变小. 泡沫的动态稳定因子经历了骤减、递增和平稳3个阶段. 泡沫前期的驱油效果主要依赖于水相, 随着含水体积基本稳定, 岩心的产油速率和泡沫动态稳定因子的增长速率具有明显正相关关系, 即中后期取决于泡沫气体对剩余油的驱替能力. 与表面活性剂泡沫相比, 纳米颗粒强化泡沫提高了低渗层的波及能力和驱油效率, 抑制了泡沫发展的不稳定阶段并且提高了动态稳定因子最终的平衡值. 该稳定性评价方法可用于反映泡沫渗流特点并筛选适合储层特征的稳定泡沫体系.      

A Two-Dimensional Network Model to Simulate Permeability Decrease Under Hydrodynamic Effect of Particle Release and Capture

A model was developed to simulate permeability decrease induced by hydrodynamic effects when injecting a fluid in a reservoir with respect to particle release and capture mechanisms and the parameters of the fluid–rock system. The kinetics of particle release and capture were integrated after computing the initial permeability of the porous medium with a square lattice of a two–dimensional network model. The rate of particle release is related to the difference between a microscopic velocity of the fluid and a critical velocity. The permeability decrease shows a direct link to the reduction of pore throat radii by three mechanisms of particle capture: straining and particle accumulation through direct interception or diffusion. Comparison between the simulations and the experimental results shows that the model reproduces the physics of the permeability decrease phenomenon, although the values are overestimated. The difference between the two sets of results can be explained by the fact that the simulations are realized at constant pressure whereas the experiments are realized at constant flow rate, and that re–entrainment of the trapped particles was not taken into account in the model.     

Co-history Matching: A Way Forward for Estimating Representative Saturation Functions

Core-scale experiments and analyses would often lead to estimation of saturation functions (relative permeability and capillary pressure). However, despite previous attempts on developing analytical and numerical methods, the estimated flow functions may not be representative of coreflood experiments when it comes to predicting similar experiments due to non-uniqueness issues of inverse problems. In this work, a novel approach was developed for estimation of relative permeability and capillary pressure simultaneously using the results of “multiple” corefloods together, which is called “co-history matching.” To examine this methodology, a synthetic (numerical) model was considered using core properties obtained from pore network model. The outcome was satisfactorily similar to original saturation functions. Also, two real coreflood experiments were performed where water at high and low rates were injected under reservoir conditions (live fluid systems) using a carbonate reservoir core. The results indicated that the profiles of oil recovery and differential pressure (dP) would be significantly affected by injection rate scenarios in non-water wet systems. The outcome of co-history matching could indicate that, one set of relative permeability and capillary pressure curves can reproduce the experimental data for all corefloods.