Approximate Solutions for Pressure Buildup During CO2 Injection in Brine Aquifers

If geo-sequestration of CO ₂ is to be employed as a key emissions reduction method in the global effort to mitigate against climate change, simple yet robust screening of the risks of disposal in brine aquifers will be needed. There has been significant development of simple analytical and semi-analytical techniques to support screening analysis and performance assessment for potential carbon sequestration sites. These techniques have generally been used to estimate the size of CO ₂ plumes for the purpose of leakage rate estimation. A common assumption is that both the fluids and the geological formation are incompressible. Consequently, calculation of pressure distribution requires the specification of an arbitrary radius of influence. In this article, a new similarity solution is derived using the method of matched asymptotic expansions. A large time approximation of this solution is then extended to account for inertial effects using the Forchheimer equation. By allowing for slight compressibility in the fluids and formation, the solutions improve on previous work by not requiring the specification of an arbitrary radius of influence. The validity of both solutions is explored by comparison with equivalent finite difference solutions, revealing that the new method can provide robust and mathematically rigorous solutions for screening level analysis, where numerical simulations may not be justified or cost effective.     

Analytical Model for CO2 Injection into Brine Aquifers-Containing Residual CH4

During CO₂ injection into brine aquifers-containing residual and/or dissolved CH₄, three distinct regions develop: (1) a single-phase, dry-out region around the well-bore filled with pure supercritical CO₂; (2) a two-phase, two-component system containing CO₂ and brine; and (3) a two-phase, two-component system containing CH₄, and brine. This article extends an existing analytical solution, for pressure buildup during CO₂ injection into brine aquifers, by incorporating dissolved and/or residual CH₄. In this way, the solution additionally accounts for partial miscibility of the CO₂?CCH₄?Cbrine system and the relative permeability hysteresis associated with historic imbibition of brine and current drainage due to CO₂ injection and CH₄ 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 CH₄ 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 CH₄ is dissolved (no free CH₄), these effects are not as important as they are in the residual gas scenario. Relative permeability hysteresis increased the CH₄ 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 CH₄ is beneficial or disadvantageous to CO₂ storage capacity and injectivity in a candid brine aquifer.     

Competitive Methane Desorption by Supercritical CO2 Injection in Coal

A large diameter (∼70 mm) dry coal sample was used to study the competitive displacement of CH₄ by injection of supercritical CO₂, and CO₂–CH₄ counter-diffusion in coal matrix. During the test, a staged loading procedure, which allows the calibration of the key reservoir modelling parameters in a sequential and progressive manner, was employed. The core-flooding test was history matched using an Enhanced Coalbed Methane (ECBM) simulator, in which Fick’s Law for mixed gas diffusion and the extended Langmuir equations are implemented. The system pressure rise during the two loading stages and the CO₂ breakthrough time in the final production stage were matched by using the pair of constant sorption times (9 and 3.2 days) for CH₄ and CO₂, respectively. The corresponding diffusion coefficients for CH₄ and CO₂ were estimated to be 1.6 ×  10⁻¹² and 4.6 ×  10⁻¹² m²/s, respectively. Comparison was made with published gas diffusion coefficients for dry ground samples (ranging from < 0.063 to ∼3 mm) of the same coal at relatively low pressures (< 4 MPa). The CO₂/CH₄ gas diffusion coefficient ratio was well within the reported range (2–3), whereas the CH₄ diffusion coefficient obtained from history matching of the core-flooding test is approximately 15 times smaller than that arrived by curve-fitting the measured sorption uptake rate using a unipore diffusion model. The calibrated model prediction of the effluent gas composition was in good agreement with the test data for CO₂ mole fraction of up to 20%.     

初应力条件下超临界CO2气爆致裂规律研究

为研究地下爆破工程中初始地应力条件下超临界CO2气爆的致裂规律,利用自主研发的三轴加载式超临界CO2气爆实验系统,对不同应力组合工况下混凝土试件进行了超临界CO2气爆致裂实验,实验结果表明超临界CO2气爆爆破峰值压力低且高压持续时间长,致裂过程不同于传统炸药爆破,分为动态和准静态过程：应力波将气爆孔附近介质压碎形成粉碎区,在环向拉应力作用下粉碎区周围介质产生径向裂隙的动态过程,高压CO2气体进入裂隙形成气楔,促使裂隙继续扩展的准静态过程,得到了气爆后试件沿最大初始压应力方向开裂的规律。通过理论计算的方法分析了初应力作用下气爆过程中介质应力状态的变化规律,揭示了初应力影响裂纹起裂和扩展的机理：位于气爆孔最大初始压应力方向的介质产生初始环向压应力最小,在超临界CO2径向冲击产生的环向拉应力作用下首先发生开裂;位于气爆孔最小初始压应力方向介质中初始环向压应力最大,开裂所需的径向冲击压力增大,开裂滞后;垂直裂隙方向的应力抑制裂隙的张开而阻碍CO2气体的进入,同时增大了裂隙扩展所需的气楔压力,气楔作用效果大幅减弱,对裂隙扩展的阻碍作用显著。裂隙的扩展速度与扩展距离呈“S型”曲线关系,初始压应力越大,裂隙扩展相同距离降低的速度值越大,且压碎区和裂隙扩展范围逐渐减小。     

二维数字图像相关测量中离面位移引起的误差分析

二维数字图像相关方法作为一种非接触全场变形测量的光学方法,在工程上有着广泛的应用.由于其假设物体只发生面内位移,而实验中往往存在离面位移,从而引起测量误差.本文针对这一问题利用了针孔模型,从理论上分析了离面位移对普通镜头测量结果的影响,通过铝块平移实验验证了理论分析的正确性.利用提出的理论模型修正橡胶材料的变形测量结果,并与远心镜头测量结果进行对比,发现修正后的普通镜头测量的结果更接近远心镜头测量的结果.最后,本文根据理论分析和实验验证,给出了减小或消除离面位移造成误差的方法.     

Impact of Initial Wettability and Injection Brine Chemistry on Mechanical Behaviour of Kansas Chalk

Transport in Porous Media - The injection of seawater-like brines alters stiffness, strength and time-dependent deformation rates for water-saturated chalks. This study deals with the mechanical...     

Buoyancy Effects on Cooling a Heat Generating Porous Medium: Coal Stockpile

In this study, the effects of buoyancy on heat and fluid flow within and around a coal stockpile are numerically investigated by both a FORTRAN code and the commercially available CFD-ACE software. Numerical simulations are backed up by theoretical results based on scale analysis. Transient variation of maximum temperature inside the coal stockpile is monitored for different coal properties. Besides, the effects of reduction of the stockpile porosity on the prevention of self-heating are studied. In doing so, on top of numerical results and as an independent prediction tool, Bejan’s Intersection of Asymptotes method is applied to find the optimum porosity of the stockpile. Finally, the energy flux vectors are used to track the correct path of energy transportation in the computational domain.     

Pressure Buildup During CO<Subscript>2</Subscript> Injection into a Closed Brine Aquifer

CO₂ injected into porous formations is accommodated by reduction in the volume of the formation fluid and enlargement of the pore space, through compression of the formation fluids and rock material, respectively. A critical issue is how the resulting pressure buildup will affect the mechanical integrity of the host formation and caprock. Building on an existing approximate solution for formations of infinite radial extent, this article presents an explicit approximate solution for estimating pressure buildup due to injection of CO₂ into closed brine aquifers of finite radial extent. The analysis is also applicable for injection into a formation containing multiple wells, in which each well acts as if it were in a quasi-circular closed region. The approximate solution is validated by comparison with vertically averaged results obtained using TOUGH2 with ECO2N (where many of the simplifying assumptions are relaxed), and is shown to be very accurate over wide ranges of the relevant parameter space. The resulting equations for the pressure distribution are explicit, and can be easily implemented within spreadsheet software for estimating CO₂ injection capacity.     

CO2 Plume Evolution and Pressure Buildup of Large-scale CO2 Injection into Saline Aquifers in Sanzhao Depression, Songliao Basin, China

Large-scale injection of carbon dioxide (CO₂) into saline aquifers in sedimentary basins is a promising approach to mitigate global climate change. Songliao Basin, a large continental clastic sedimentary basin in northeastern China, is one of the great potential candidate sites for future CO₂ storage in China. In this paper, a three-dimensional CO₂ storage model was built to evaluate the CO₂ plume evolution and pressure buildup of large-scale CO₂ injection into the saline aquifers in the Sanzhao Depression of the Songliao Basin. CO₂ was injected into the aquifers through five wells, each with an annual injection rate of 3 Mt over 50?years. The results show that the clastic Yaojia formation at the depth between 900 and 1,600 m with thickness of 150 m might be the favorable layer to store a considerable amount of CO₂, and the overlying Nenjiang formation could ensure long-term CO₂ containment. The relative low permeability of the upper part of the Yaojia formation seems to play a role of a secondary seal on carbon storage. In current injection scenario, CO₂ plume migrates into the formations in the southeast of the depression, which could have potential risk of polluting the freshwater. Therefore, the injection site should stay far away from the southeast of the depression. Moreover, it is very crucial to investigate the permeability distribution of the Yaojia formation because it significantly dominates the CO₂ plume migration. After only 6?months of injection, the pressure buildup at each injection site is affected by pressure interference from neighboring sites. The maximum pressure buildup in the formations is 7.8?MPa after 50?years of injection, and it can even reach 10.5?MPa when the injection layers are with lower permeability. The maximum pressure buildup at the bottom of the Nenjiang formation is 6.7?MPa. The gradient of maximum limited formation pressure is about 18?MPa/km, which might cause fractures to open in the formations of the Sanzhao Depression. Continuous injection of CO₂ for 50?years may not cause damage to the caprock even when the lower permeability occurred in the upper part of the Yaojia formation. The safety of CO₂ storage will be enhanced if the upper part of the storage formation has lower permeability than the lower part.     

Impact of Capillary Pressure, Salinity and In situ Conditions on CO2 Injection into Saline Aquifers

This article presents a numerical investigation of the combined effects of capillary pressure, salinity and in situ thermodynamic conditions on CO₂-brine-rock interactions in a saline aquifer. We demonstrate that the interrelations between capillary pressure, salinity, dissolution and drying-out affect CO₂ 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 CO₂ in formation water and its compressibility. Higher capillary forces also reduce gravity segregation, and this gives a more homogeneous CO₂ plume which improves the dissolution of CO₂. The solubility of CO₂ 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, CO₂ 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 CO₂ density and compressibility for storage in warm basins.     

Effect of the Chemical Reaction and Injection on Flow Characteristics in an Unsteady Upward Motion of an Isothermal Plate

The transient incompressible viscous fluid flow regime past a semiinfinite isothermal plate under conditions of natural convection is studied numerically. The solution obtained takes into account the firstorder homogeneous chemical reaction and the mass flux through the plate. The calculated velocity profile is in good agreement with the known exact solution. Velocity, temperature, and concentration profiles are presented. It is shown that the fluid velocity decreases with increasing chemical reaction parameter. The distributions of local and averaged values of skin friction and Nusselt and Sherwood numbers are analyzed.     

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.     

Modeling of Spatiotemporal Thermal Response to CO2 Injection in Saline Formations: Interpretation for Monitoring

We evaluated the thermal processes with numerical simulation models that include processes of solid NaCl precipitation, buoyancy-driven multiphase SCCO₂ migration, and potential non-isothermal effects. Simulation results suggest that these processes??solid NaCl precipitation, buoyancy effects, JT cooling, water vaporization, and exothermic SCCO₂ reactions??are strongly coupled and dynamic. In addition, we performed sensitivity studies to determine how geologic (heat capacity, brine concentration, porosity, the magnitude and anisotropy of permeability, and capillary pressure) and operational (injection rate and injected SCCO₂ temperature) parameters may affect these induced thermal disturbances. Overall, a fundamental understanding of potential thermal processes investigated through this research will be beneficial in the collection and analysis of temperature signals collectively measured from monitoring wells.     

Visual Investigation of Improvement in Extra-Heavy Oil Recovery by Borate-Assisted $$\hbox {CO}_{2}$$-Foam Injection

The significant reduction in heavy oil viscosity when mixed with \(\hbox {CO}_{2}\) is well documented. However, for \(\hbox {CO}_{2}\) injection to be an efficient method for improving heavy oil recovery, other mechanisms are required to improve the mobility ratio between the \(\hbox {CO}_{2}\) front and the resident heavy oil. In situ generation of \(\hbox {CO}_{2}\)-foam can improve \(\hbox {CO}_{2}\) injection performance by (a) increasing the effective viscosity of \(\hbox {CO}_{2}\) in the reservoir and (b) increasing the contact area between the heavy oil and injected \(\hbox {CO}_{2}\) and hence improving \(\hbox {CO}_{2}\) dissolution rate. However, in situ generation of stable \(\hbox {CO}_{2}\)-foam capable of travelling from the injection well to the production well is hard to achieve. We have previously published the results of a series of foam stability experiments using alkali and in the presence of heavy crude oil (Farzaneh and Sohrabi 2015). The results showed that stability of \(\hbox {CO}_{2}\)-foam decreased by addition of NaOH, while it increased by addition of \(\hbox {Na}_{2}\hbox {CO}_{3}\). However, the highest increase in \(\hbox {CO}_{2}\)-foam stability was achieved by adding borate to the surfactant solution. Borate is a mild alkaline with an excellent pH buffering ability. The previous study was performed in a foam column in the absence of a porous medium. In this paper, we present the results of a new series of experiments carried out in a high-pressure glass micromodel to visually investigate the performance of borate–surfactant \(\hbox {CO}_{2}\)-foam injection in an extra-heavy crude oil in a transparent porous medium. In the first part of the paper, the pore-scale interactions of \(\hbox {CO}_{2}\)-foam and extra-heavy oil and the mechanisms of oil displacement and hence oil recovery are presented through image analysis of micromodel images. The results show that very high oil recovery was achieved by co-injection of the borate–surfactant solution with \(\hbox {CO}_{2}\), due to in-situ formation of stable foam. Dissolution of \(\hbox {CO}_{2}\) in heavy oil resulted in significant reduction in its viscosity. \(\hbox {CO}_{2}\)-foam significantly increased the contact area between the oil and \(\hbox {CO}_{2}\) significantly and thus the efficiency of the process. The synergy effect between the borate and surfactant resulted in (1) alteration of the wettability of the porous medium towards water wet and (2) significant reduction of the oil–water IFT. As a result, a bank of oil-in-water (O/W) emulsion was formed in the porous medium and moved ahead of the \(\hbox {CO}_{2}\)-foam front. The in-situ generated O/W emulsion has a much lower viscosity than the original oil and plays a major role in the observed additional oil recovery in the range of performed experiments. Borate also made \(\hbox {CO}_{2}\)-foam more stable by changing the system to non-spreading oil and reducing coalescence of the foam bubbles. The results of these visual experiments suggest that borate can be a useful additive for improving heavy oil recovery in the range of the performed tests, by increasing \(\hbox {CO}_{2}\)-foam stability and producing O/W emulsions.     

Long-Term Evolution of Coal Permeability Under Effective Stresses Gap Between Matrix and Fracture During CO2 Injection

Transport in Porous Media - Understanding the long-term evolution of coal permeability under the influence of gas adsorption-induced multiple processes is crucial for the efficient sequestration of...     

超临界CO2气爆煤体致裂机理实验研究

为提高超临界CO₂气爆低渗透煤层增透技术的应用水平,进一步研究超临界CO₂气爆煤体致裂机理,利用自主研发的超临界CO₂气爆装置,在多通道电液伺服相似材料试验台上,对原煤和混凝土大试件(1 m×1 m×0.5 m)进行了超临界CO₂气爆实验,用动态应变仪采集试件内部监测点处的变形和破坏信息,并用工业窥镜对爆破孔内裂隙分布进行了观测。分析气爆应力波的变化规律和气爆后试件的破坏形貌特征可知,距离气爆孔由近及远依次分为粉碎区、裂隙区和震动区,其形成机理为:超临界CO₂冲击气爆孔周围介质并形成远超介质抗压强度的球面纵波,介质在径向压应力作用下发生粉碎性破坏,形成粉碎区;应力波传播能量逐步衰减,不足以使介质产生压缩破坏,然而脆性材料抗压不抗拉,其产生的环向应力仍然使介质产生径向裂隙,应力波之后具有准静态加载作用的高压CO₂气体进入裂隙形成气楔,促使裂隙进一步发育和扩展,形成裂隙区;裂隙区以外的介质在低能量应力波的作用下只发生震动,未发生明显破坏,即震动区。裂隙的扩展速度与其到气爆孔距离符合“S”形曲线衰减,裂隙的高速扩展发生在粉碎区,低速扩展发生在裂隙区;距离气爆孔越远,测点的峰值应变越小,相同距离内节理裂隙等结构面越复杂,峰值应变减小的幅度越大且应变波形差别越大。     

Analysis of Compositional Effects on Global Flow Regimes in CO2 Near-Miscible Displacements in Heterogeneous Systems

Transport in Porous Media - The objective of this paper is developing new methodology for constructing the inflow performance relationships (IPRs) of unconventional reservoirs experiencing...     

载荷及位移幅值对DLC薄膜微动磨损行为的影响

为了提高TC4钛合金表面的抗微动磨损性能,在本文中采用非平衡磁控溅技术(Unbalanced Magnetron Sputtering)在TC4钛合金表面沉积了类金刚石(DLC)薄膜. 采用球/平面接触形式研究了DLC薄膜的微动摩擦磨损行为. 在不同法向载荷和位移幅值下,结合微动运行工况图研究了DLC薄膜滑移状态和损伤机理. 利用原子力显微镜、纳米压痕仪、激光拉曼光谱仪、激光共聚焦显微镜、场发射扫描电子显微镜和SRV-V微动摩擦磨损试验机等设备对DLC薄膜进行性能的表征和微动摩擦磨损性能测试. 通过微动图,摩擦耗散能,磨痕形貌、化学成分分析揭示其损伤机理. 结果表明:载荷和位移幅值对DLC薄膜微动摩擦磨损行为和损伤机理有显著影响. 当位移幅值为25 μm 时,微动运行于混合滑移(mixed slip regime,MSR)情形下,当位移幅值为100 μm时,微动运行于完全滑移(gross slip regime,GSR)情形下. 小位移幅值时,DLC薄膜磨损机理是磨粒磨损为主;大位移幅值时,DLC薄膜磨损机理是黏着磨损为主. 干摩擦条件下,DLC薄膜有良好的抗微动磨损性能,关键就在于其优异力学性能和自润滑特性.      

Semianalytical Solution for \text{ CO}_{2} Plume Shape and Pressure Evolution During \text{ CO}_{2} Injection in Deep Saline Formations

The injection of supercritical carbon dioxide ( $\text{ CO}_{2})$ in deep saline aquifers leads to the formation of a $\text{ CO}_{2}$ rich phase plume that tends to float over the resident brine. As pressure builds up, $\text{ CO}_{2}$ density will increase because of its high compressibility. Current analytical solutions do not account for $\text{ CO}_{2}$ compressibility and consider a volumetric injection rate that is uniformly distributed along the whole thickness of the aquifer, which is unrealistic. Furthermore, the slope of the $\text{ CO}_{2}$ pressure with respect to the logarithm of distance obtained from these solutions differs from that of numerical solutions. We develop a semianalytical solution for the $\text{ CO}_{2}$ plume geometry and fluid pressure evolution, accounting for $\text{ CO}_{2}$ compressibility and buoyancy effects in the injection well, so $\text{ CO}_{2}$ is not uniformly injected along the aquifer thickness. We formulate the problem in terms of a $\text{ CO}_{2}$ potential that facilitates solution in horizontal layers, with which we discretize the aquifer. Capillary pressure is considered at the interface between the $\text{ CO}_{2}$ rich phase and the aqueous phase. When a prescribed $\text{ CO}_{2}$ mass flow rate is injected, $\text{ CO}_{2}$ advances initially through the top portion of the aquifer. As $\text{ CO}_{2}$ is being injected, the $\text{ CO}_{2}$ plume advances not only laterally, but also vertically downwards. However, the $\text{ CO}_{2}$ plume does not necessarily occupy the whole thickness of the aquifer. We found that even in the cases in which the $\text{ CO}_{2}$ plume reaches the bottom of the aquifer, most of the injected $\text{ CO}_{2}$ enters the aquifer through the layers at the top. Both $\text{ CO}_{2}$ plume position and fluid pressure compare well with numerical simulations. This solution permits quick evaluations of the $\text{ CO}_{2}$ plume position and fluid pressure distribution when injecting supercritical $\text{ CO}_{2}$ in a deep saline aquifer.