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1.
In CO2 geological storage (CGS) context, the evolution of the caprock sealing capacity has received increasing attention, particularly on a geological time span (thousands of years). At this time scale, geochemical reactions may enhance or weaken the caprock quality. It is widely recognized that, for the reservoir, geological heterogeneities affect the concentration and spatial distribution of CO2, and then affect the extent of gas–water–rock interactions, which in turn alters the hydrogeological properties of the reservoir. However, much less attention of these effects has been paid to the caprock. In this study, we presented and applied a novel approach to evaluate the effects of permeability and porosity heterogeneities on the alteration of minerals, the associated evolution of the caprock sealing efficiency and the containment of supercritical CO2 (scCO2) within the caprock. Even though this is a generic study, several conditions and parameters such as pressure, permeability, and mineral composition, were extracted from a caprock layer of the Shiqianfeng Formation in the Ordos Basin demonstration site in China. For the sake of simplification, a 2-dimensional model was designed to represent the caprock domain. We firstly generated an appropriate heterogeneous random field of permeability with the average permeability taken from the uppermost mudstone layer of the Shiqianfeng Formation, and then the heterogeneity in porosity was incorporated using a joint normal distribution method based on the available data. Homogeneous mineral compositions of the reservoir and caprock were used in all simulations. Simulations of three cases were performed, including a homogeneous case, a case with only permeability heterogeneity and a case with both permeability and porosity heterogeneities. The results demonstrate dramatic influences of permeability and porosity heterogeneities on the migration of scCO2 within the caprock, the alteration of minerals, and therefore the evolution of the caprock sealing quality. Specific to the data used in this study, hydrogeological heterogeneities facilitated the overall penetration of scCO2 within the caprock and promoted the alteration of minerals, thereby weakening the caprock sealing efficiency over the simulation time.  相似文献   

2.
Numerical models are essential tools in fully understanding the fate of injected CO2 for commercial-scale sequestration projects and should be included in the life cycle of a project. Common practice involves modeling the behavior of CO2 during and after injection using site-specific reservoir and caprock properties. Little has been done to systematically evaluate and compare the effects of a broad but realistic range of reservoir and caprock properties on potential CO2 leakage through caprocks. This effort requires sampling the physically measurable range of caprock and reservoir properties, and performing numerical simulations of CO2 migration and leakage. In this study, factors affecting CO2 leakage through intact caprocks are identified. Their physical ranges are determined from the literature from various field sites. A quasi-Monte Carlo sampling approach is used such that the full range of caprock and reservoir properties can be evaluated without bias and redundant simulations. For each set of sampled properties, the migration of injected CO2 is simulated for up to 200 years using the water–salt–CO2 operational mode of the STOMP simulator. Preliminary results show that critical factors determining CO2 leakage rate through caprocks are, in decreasing order of significance, the caprock thickness, caprock permeability, reservoir permeability, caprock porosity, and reservoir porosity. This study provides a function for prediction of potential CO2 leakage risk due to permeation of intact caprock and identifies a range of acceptable seal thicknesses and permeability for sequestration projects. The study includes an evaluation of the dependence of CO2 injectivity on reservoir properties.  相似文献   

3.
Crushed rock from two caprock samples, a carbonate-rich shale and a clay-rich shale, were reacted with a mixture of brine and supercritical CO2 (CO2–brine) in a laboratory batch reactor, at different temperature and pressure conditions. The samples were cored from a proposed underground CO2 storage site near the town of Longyearbyen in Svalbard. The reacting fluid was a mixture of 1 M NaCl solution and CO2 (110 bar) and the water/rock ratio was 20:1. Carbon dioxide was injected into the reactors after the solution had been bubbled with N2, in order to mimic O2-depleted natural storage conditions. A control reaction was also run on the clay-rich shale sample, where the crushed rock was reacted with brine (CO2-free brine) at the same experimental conditions. A total of 8 batch reaction experiments were run at temperatures ranging from 80 to 250 °C and total pressures of 110 bar (∼40 bar for the control experiment). The experiments lasted 1–5 weeks.Fluid analysis showed that the aqueous concentration of major elements (i.e. Ca, Mg, Fe, K, Al) and SiO2 increased in all experiments. Release rates of Fe and SiO2 were more pronounced in solutions reacted with CO2–brine as compared to those reacted with CO2-free brine. For samples reacted with the CO2–brine, lower temperature reactions (80 °C) released much more Fe and SiO2 than higher temperature reactions (150–250 °C). Analysis by SEM and XRD of reacted solids also revealed changes in mineralogical compositions. The carbonate-rich shale was more reactive at 250 °C, as revealed by the dissolution of plagioclase and clay minerals (illite and chlorite), dissolution and re-precipitation of carbonates, and the formation of smectite. Carbon dioxide was also permanently sequestered as calcite in the same sample. The clay-rich shale reacted with CO2–brine did not show major mineralogical alteration. However, a significant amount of analcime was formed in the clay-rich shale reacted with CO2-free brine; while no trace of analcime was observed in either of the samples reacted with CO2–brine.  相似文献   

4.
The most suitable candidates for subsurface storage of CO2 are depleted gas fields. Their ability to retain CO2 can however be influenced by the effect which impurities in the CO2 stream (e.g. H2S and SO2) have on the mineralogy of reservoir and seal. In order to investigate the effects of SO2 we carried out laboratory experiments on reservoir and cap rock core samples from gas fields in the northeast of the Netherlands. The rock samples were contained in reactor vessels for 30 days in contact with CO2 and 100 ppm SO2 under in-situ conditions (300 bar, 100 °C). The vessels also contained brine with the same composition as in the actual reservoir. Furthermore equilibrium modeling was carried out using PHREEQC software in order to model the experiments on caprock samples.After the experiments the permeability of the reservoir samples had increased by a factor of 1.2–2.2 as a result of dissolution of primary reservoir minerals. Analysis of the associated brine samples before and after the experiments showed that concentrations of K, Si and Al had increased, indicative of silicate mineral dissolution.In the caprock samples, composed of carbonate and anhydrite minerals, permeability changed by a factor of 0.79–23. The increase in permeability is proportional to the amount of carbonate in the caprock. With higher carbonate content in comparison with anhydrite the permeability increase is higher due to the additional carbonate dissolution. This dependency of permeability variations was verified by the modeling study. Hence, caprock with a higher anhydrite content in comparison with carbonate minerals has a lower risk of leakage after co-injection of 100 ppmv SO2 with CO2.  相似文献   

5.
The integrity of wells, which are key components for CO2 sequestration, depends mainly on the seal between the wellbore cement and the geologic formation. To identify the reaction products that may alter the cement/caprock interface, batch experiments and computer modelling were conducted and analysed. Over time, the dissolution and precipitation of minerals alters the physical properties of the interface, including its tightness. One main objective of the simulation was thus to analyse the evolution of the porosity of cement and caprock over time. The alteration of the cement/caprock interface was identified as a complex problem and differentiated depending on rock type. The characteristic feature of a cement/shale contact zone is the occurrence of a highly carbonated, compacted layer within the shale, which in turn causes cement/shale detachment. In the case of a cement/anhydrite interface, the most important reaction is severe anhydrite dissolution. Secondary calcite precipitation takes place in deeper parts of the rock. The cement/rock contact zone is prone to rapid mineral dissolution, which contributes to increased porosity and may alter the well integrity. Comparison of computer simulations with autoclave experiments enabled the adjustment of unknown parameters. This enhances the knowledge of these particular assemblages. Overall, a good match was obtained between experiments and simulations, which enhances confidence in using models to predict longer-term evolution.  相似文献   

6.
We use a reactive diffusion model to investigate what happens to CO2 injected into a subsurface sandstone reservoir capped by a chlorite- and illite-containing shale seal. The calculations simulate reaction and transport of supercritical (SC) CO2 at 348.15 K and 30 MPa up to 20,000 a. Given the low shale porosity (5%), chemical reactions mostly occurred in the sandstone for the first 2000 a with some precipitation at the ss/sh interface. From 2000 to 4000 a, ankerite, dolomite and illite began replacing Mg–Fe chlorite at the sandstone/shale interface. Transformation of chlorite to ankerite is the dominant reaction occluding the shale porosity in most simulations: from 4000 to 7500 a, this carbonation seals the reservoir and terminates reaction. Overall, the carbonates (calcite, ankerite, dolomite), chlorite and goethite all remain close to local chemical equilibrium with brine. Quartz is almost inert from the point of its dissolution/precipitation. However, the rate of quartz reaction controls the long-term decline in aqueous silica activity and its evolution toward equilibrium. The reactions of feldspars and clays depend strongly on their reaction rate constants (microcline is closer to local equilibrium than albite). The timing of porosity occlusion mostly therefore depends on the kinetic constants of kaolinite and illite. For example, an increase in the kaolinite kinetic constant by 0.25 logarithmic units hastened porosity closure by 4300 a. The earliest simulated closure of porosity occurred at approximately 108 a for simulations designed as sensitivity tests for the rate constants.These simulations also emphasize that the rate of CO2 immobilization as aqueous bicarbonate (solubility trapping) or as carbonate minerals (mineral trapping) in sandstone reservoirs depends upon reaction kinetics – but the relative fraction of each trapped CO2 species only depends upon the initial chemical composition of the host sandstone. For example, at the point of porosity occlusion the fraction of bicarbonate remaining in solution depends upon the initial Na and K content in the host rock but the fraction of carbonate mineralization depends only on the Ca, Mg, Fe content. Since ankerite is the dominant mineral that occludes porosity, the dissolved concentration of ferrous iron is also an important parameter. Future efforts should focus on cross-comparisons and ground-truthing of simulations made for standard case studies as well as laboratory measurements of the reactivities of clay minerals.  相似文献   

7.

Background

Reactive-transport simulation is a tool that is being used to estimate long-term trapping of CO2, and wellbore and cap rock integrity for geologic CO2 storage. We reacted end member components of a heterolithic sandstone and shale unit that forms the upper section of the In Salah Gas Project carbon storage reservoir in Krechba, Algeria with supercritical CO2, brine, and with/without cement at reservoir conditions to develop experimentally constrained geochemical models for use in reactive transport simulations.

Results

We observe marked changes in solution composition when CO2 reacted with cement, sandstone, and shale components at reservoir conditions. The geochemical model for the reaction of sandstone and shale with CO2 and brine is a simple one in which albite, chlorite, illite and carbonate minerals partially dissolve and boehmite, smectite, and amorphous silica precipitate. The geochemical model for the wellbore environment is also fairly simple, in which alkaline cements and rock react with CO2-rich brines to form an Fe containing calcite, amorphous silica, smectite and boehmite or amorphous Al(OH)3.

Conclusions

Our research shows that relatively simple geochemical models can describe the dominant reactions that are likely to occur when CO2 is stored in deep saline aquifers sealed with overlying shale cap rocks, as well as the dominant reactions for cement carbonation at the wellbore interface.  相似文献   

8.
Safety assessment of geosequestration of CO2 into deep saline aquifers requires a precise understanding of the study of hydro‐chemo‐mechanical couplings occurring in the rocks and the cement well. To this aim, a coupled chemo‐poromechanical model has been developed and implemented into a research code well‐suited to the resolution of fully coupled problems. This code is based on the finite volume methods. In a 1D axisymmetrical configuration, this study aims to simulate the chemo‐poromechanical behaviour of a system composed by the cement well and the caprock during CO2 injection. Major chemical reactions of carbonation occurring into cement paste and rocks are considered in order to evaluate the consequences of the presence of CO2 on the amount of dissolved matrix and precipitated calcium carbonates. The dissolution of the solid matrix is taken into account through the use of a chemical porosity. Matrix leaching and carbonation lead, as expected, to important variations of porosity, permeability and to alterations of transport properties and mechanical stiffness. These results justify the importance of considering a coupled analysis accounting for the main chemical reactions. It is worth noting that the modelling framework proposed in the present study could be extended to model the chemo‐poromechanical behaviour of the reservoir rock and the caprock when subjected to the presence of an acidic pore fluid (CO2‐rich brine). Copyright © 2013 John Wiley & Sons, Ltd.  相似文献   

9.
鄂尔多斯盆地是我国CO2地下埋藏的潜在目标区,位于伊金霍洛旗附近的中神监X井与CO2地下注入井中神注1井相邻,两者钻遇地层系统和岩石组合一致。为对示范区储层的固碳潜力和泥岩改造状况做出预测,为CO2地质储存的数值模拟研究提供基础地质信息和相关数据,通过偏光显微镜、扫描电镜、X射线衍射、X射线荧光等多种技术手段,开展了中神监X井石千峰组的岩石学和地球化学特征研究。结果表明石千峰组的砂岩岩石类型主要为长石岩屑砂岩和岩屑长石砂岩;泥岩主要由石英、粘土矿物和长石组成,其中,粘土矿物主要为伊利石,其次为蒙皂石、高岭石和绿泥石。预测在CO2注入后的流体-砂岩长期相互作用过程中,石千峰组砂岩可以通过形成片钠铝石、方解石、铁白云石和菱铁矿等固碳矿物,形成对CO2泄露而言的矿物圈闭,进而实现CO2的长期和安全封存;红色泥岩夹层将发生金属离子活化,导致泥岩褪色。  相似文献   

10.
辽河盆地东部凹陷天然气盖层评价   总被引：9，自引：0，他引：9  
张占文  陈永成 《沉积学报》1996,14(4):102-107
辽河盆地东部凹陷为辽河盆地三大凹陷之一，位于辽宁省境内的下辽河平原。本文通过东部凹陷盖层类型，岩石学特征与盖层品质的关系，压实作用对盖层封盖性能的影响及火山岩盖层封盖性能分析，指出东部凹陷虽缺乏区域性盖层，但局部盖层十分发育，其中火山岩是最好的盖层，不同层次的泥岩盖层变化较大，主要形成期为中深层的突变压实阶段和紧密压实阶段，浅层火山岩的发育弥补了泥岩的不足，并根据泥岩盖层与储层的匹配关系研究指出:“东部凹陷浅层是差的盖层匹配好储层，深层则相反”。从泥岩盖层角度出发认为中深层应是大中型气藏形成的有利场所，浅层则是小型气藏发育的有利部位，但本区封盖性能很好的火山岩发育，使其为主的盖层，增加了浅层形成较大型气藏的可能，从而打破了以泥岩盖层为主的纵向天然气分布格局，同时通过东部凹陷不同层位、不同深度层次泥岩盖层突破压力分布特点，结合火山岩分布特征，指出了本区下部勘探方向。  相似文献   

11.
昭通国家级页岩气示范区黄金坝气田是继礁石坝和长宁—威远之后中国又一个在页岩气勘探、开发领域实现重大突破的地区,为了系统地展示黄金坝气田页岩气资源富集的储层条件,为未来的勘探工作提供参考,以五峰—龙马溪组页岩气储层为研究对象,从区域地质条件、储层岩石学、物性和地球化学4个方面对该页岩气储层进行了综合研究。结果表明稳定的区域构造和良好的顶底板条件是黄金坝地区页岩气资源富集的关键,良好的保存条件使储层维持了较高的压力(压力系数1);较高的孔隙度(平均4%)和TOC含量(目的层2%)提供了良好的储集空间,使储层具有较高的含气量(1.35~3.48 cm3/g,平均2.50 cm3/g);天然气地球化学数据表明,区内天然气主要成分为CH4(97%),其次还含有少量的C2H6、C3H8和CO2;天然气同位素数据表明烃类C同位素组成发生了倒转,表明储层具有良好的封闭性。但储层孔隙系统较为复杂,且非均质性极强,从而导致渗透率较低,在储层改造施工过程中应予以充分考虑。总体上,黄金坝气田具有较好的开发前景,生产测试表明,区内直井压裂产量为0.5×104~3.5×104m3/d/井,水平井压裂产量可达12×104~40×104m3/d/井。  相似文献   

12.
The well-developed continental shale sequences in the Western Sichuan Depression are characterised by extremely low porosity and permeability, complex lithologies and strong lateral facies changes. The overall lack of proper characterisation of the shale properties has restricted gas exploration and development in the region. In this study, shales from the fifth member of the Xujiahe Formation of the Upper Triassic (T3x5) are comprehensively characterised in terms of their organic geochemistry, mineral composition, microscopic pore structure and gas content. In addition, the influence of various geological factors on the adsorbed gas content is investigated. We proposed a new model for predicting the adsorption gas content of continental shale. The T3x5 shale sequence is found to be rich in organic matter but with variable mineral compositions, pore types and reservoir physical properties. The porosity and permeability of shales are better than those of siltstones and fine sandstones interbedded with the shale under an overall densification background. Mesopores (2–50 nm) are common in the shale sequence, followed by micropores and then macropores. The gas-adsorption capacity of organic-rich shales increases with increasing TOC and clay-mineral contents, maturity and pressure, but decreases with increasing quartz content, carbonate minerals and temperature. The gas-adsorption capacity can thus be expressed as a function of organic matter, clay-mineral content, temperature and pressure. The calculated results are in good agreement with the experiment results and indicate that adsorption gas in the studied shales accounts for 78.9% of the total gas content.  相似文献   

13.
Reservoir and cap-rock core samples with variable lithology's representative of siliciclastic reservoirs used for CO2 storage have been characterized and reacted at reservoir conditions with an impure CO2 stream and low salinity brine. Cores from a target CO2 storage site in Queensland, Australia were tested. Mineralogical controls on the resulting changes to porosity and water chemistry have been identified. The tested siliciclastic reservoir core samples can be grouped generally into three responses to impure CO2-brine reaction, dependent on mineralogy. The mineralogically clean quartzose reservoir cores had high porosities, with negligible change after reaction, in resolvable porosity or mineralogy, calculated using X-ray micro computed tomography and QEMSCAN. However, strong brine acidification and a high concentration of dissolved sulphate were generated in experiments owing to minimal mineral buffering. Also, the movement of kaolin has the potential to block pore throats and reduce permeability. The reaction of the impure CO2-brine with calcite-cemented cap-rock core samples caused the largest porosity changes after reaction through calcite dissolution; to the extent that one sample developed a connection of open pores that extended into the core sub-plug. This has the potential to both favor injectivity but also affect CO2 migration. The dissolution of calcite caused the buffering of acidity resulting in no significant observable silicate dissolution. Clay-rich cap-rock core samples with minor amounts of carbonate minerals had only small changes after reaction. Created porosity appeared mainly disconnected. Changes were instead associated with decreases in density from Fe-leaching of chlorite or dissolution of minor amounts of carbonates and plagioclase. The interbedded sandstone and shale core also developed increased porosity parallel to bedding through dissolution of carbonates and reactive silicates in the sandy layers. Tight interbedded cap-rocks could be expected to act as baffles to fluids preventing vertical fluid migration. Concentrations of dissolved elements including Ca, Fe, Mn, and Ni increased during reactions of several core samples, with Mn, Mg, Co, and Zn correlated with Ca from cap-rock cores. Precipitation of gypsum, Fe-oxides and clays on seal core samples sequestered dissolved elements including Fe through co-precipitation or adsorption. A conceptual model of impure CO2-water-rock interactions for a siliciclastic reservoir is discussed.  相似文献   

14.
鄂尔多斯盆地中部上古生界山西组页岩储层特征   总被引：4，自引：1，他引：3  
鄂尔多斯盆地山西组发育一套厚度大且有勘探潜力的陆海陆过渡相页岩。应用岩芯观察、X衍射、扫描电镜和显微镜观察以及高压压汞等方法,对该盆地中部山西组页岩的岩石学、矿物学、页岩储集空间、孔隙结构和物性特征进行分析研究。结果表明:研究区山西组页岩以黑色泥岩、黑色页岩夹纹层或薄层状深色粉砂岩为主,页岩主要由黏土矿物和石英两类矿物组成,二者平均含量分别为59.6%和36.9%。页岩宏观和微观裂隙发育,显微镜下统计的显微裂缝平均面密度达到116.6/m。除了发育与矿物和成岩作用有关的矿物孔隙外,页岩中有机显微组分发育较多的有机质孔。页岩孔隙度平均为0.77%,渗透率平均为0.06×10-3 μm2。山西组页岩总有机碳（TOC）、镜质体反射率（Ro,%）和黏土矿物含量是影响页岩孔隙度的主要因素,具有正相关性,而石英含量与页岩孔隙度呈一定的负相关关系。山西组页岩中裂缝的普遍发育提高了页岩的渗透率,有利于页岩气聚集成藏。综合分析表明山西组页岩气储层地质条件一般,开发难度较大,但在裂缝发育、物性较好的层位和地区仍具有较好的页岩气资源前景。  相似文献   

15.
The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO2-EGR (enhanced gas recovery), and CO2-storage. A generic 3D planer model (20,000?×?3,000?×?100?m, consisting of 1,200?m overburden, 100?m caprock, 200?m gas reservoir, and 1,500?m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO2-EGR phase under a balanced injection rate (31,500?tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4?% in the 5-year CO2-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83?% for 5?km distance, instead of 1.2?km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO2-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6?MPa which is determined by the penetration criterion of the caprock.  相似文献   

16.
有机质孔隙是页岩储集空间的重要组成部分,具有强烈的非均质性,阻碍对页岩储层质量的正确认识和评价,其本质是受有机显微组分类型及其在生烃过程中孔隙演化的影响。本文采用场发射扫描电镜和荧光显微镜定位观察手段实现特定显微组分孔隙发育特征的表征,结合Image J图像处理技术,对不同演化阶段的显微组分进行定量化统计,总结不同有机显微组分的孔隙演化规律。研究结果表明:固体沥青孔隙度随着成熟度的升高呈现先增加后减小的趋势,在固体沥青反射率SBR_O介于1.6%～2.0%时,固体沥青孔隙最为发育,而以SBR_O=2.0%为界,固体沥青孔隙度开始减小。镜质体和惰质体的孔隙发育规律相似,随着成熟度增加,总体表现出先减小而后微弱增加的趋势。在生油窗阶段,镜质体和惰质体孔隙度最小,无机矿物和固体沥青的充填使胞腔孔隙损失达90%以上,而进入高成熟阶段,固体沥青孔隙的发育使原始胞腔孔隙得到一定程度的恢复,成为镜质体和惰质体残余孔隙的主要贡献者,贡献率达56.73%和100%,可见固体沥青孔隙对页岩储层储集空间的重要性。综合沉积成岩作用和生烃作用,页岩储层在未成熟阶段和高成熟阶段晚期孔隙最为发育,前者有机质以原始胞腔孔隙为主,后者以固体量孔隙为主。明确有机显微组分孔隙演化规律为页岩有利储层预测和页岩气生产开发储层改造提供参考。  相似文献   

17.
Deep saline aquifers in sedimentary basins are considered to have the greatest potential for CO2 geological storage in order to reduce carbon emissions. CO2 injected into a saline sandstone aquifer tends to migrate upwards toward the caprock because the density of the supercritical CO2 phase is lower than that of formation water. The accumulated CO2 in the upper portions of the reservoir gradually dissolves into brine, lowers pH and changes the aqueous complexation, whereby induces mineral alteration. In turn, the mineralogical composition could impose significant effects on the evolution of solution, further on the mineralized CO2. The high density of aqueous phase will then move downward due to gravity, give rise to “convective mixing,” which facilitate the transformation of CO2 from the supercritical phase to the aqueous phase and then to the solid phase. In order to determine the impacts of mineralogical compositions on trapping amounts in different mechanisms for CO2 geological storage, a 2D radial model was developed. The mineralogical composition for the base case was taken from a deep saline formation of the Ordos Basin, China. Three additional models with varying mineralogical compositions were carried out. Results indicate that the mineralogical composition had very obvious effects on different CO2 trapping mechanisms. Specific to our cases, the dissolution of chlorite provided Mg2+ and Fe2+ for the formation of secondary carbonate minerals (ankerite, siderite and magnesite). When chlorite was absent in the saline aquifer, the dominant secondary carbon sequestration mineral was dawsonite, and the amount of CO2 mineral trapping increased with an increase in the concentration of chlorite. After 3000 years, 69.08, 76.93, 83.52 and 87.24 % of the injected CO2 can be trapped in the solid (mineral) phase, 16.05, 11.86, 8.82 and 6.99 % in the aqueous phase, and 14.87, 11.21, 7.66 and 5.77 % in the gas phase for Case 1 through 4, respectively.  相似文献   

18.
第四系泥岩型生物气作为非常规油气领域一种新型的资源类型,具有巨大的资源潜力和勘探开发价值。以柴达木盆地三湖地区第四系泥岩型生物气为例,通过岩心观察、光学显微镜、扫描电镜、高压压汞、族组分分析等实验手段,分析了第四系泥岩型生物气储层特征及动态成藏过程。结果表明,第四系泥岩型生物气储层具有砂泥薄互层频繁交互、纵横向非均质性极强的特点。成岩作用处于早期阶段,Ro小于0.3%,岩石固结程度低,含贝类壳体没有石化,孔隙度普遍在20%以上,仍以微纳米孔隙为主,含极少量毫米孔隙。泥岩储层TOC极低,平均0.2%~0.4%,干酪根以Ⅲ型为主,主要成分是粗纤维,其次是半纤维素、有机氮,是第四系泥岩生气的主要母质来源。第四系泥岩型生物气为甲烷为主的干气,平均含量98.85%,地层水水型以CaCl2型为主,酸碱度中等偏弱酸性。泥岩突破压力是甲烷滞留成藏的主要动力,低渗、富水和黏土的特征决定了泥岩具备自封闭能力。极低的气候温度、极高的水体盐度、充足的气源条件、有效的自封闭性是泥岩型生物气成藏的关键要素,以此建立了凹陷区自封闭富集带、斜坡区水封富集带、构造高点泥岩气-砂岩气叠合富集带等三种泥岩型生物气成藏模式。  相似文献   

19.
This article performed a series of parallel experiments with numerical modeling to reveal key factors affecting the gas adsorption capacity of shale, including shale quality, gas composition and geological conditions. Adsorption experiments for shales with similar OM types and maturities indicate that the OM is the core carrier for natural gas in shale, while the clay mineral has limited effect. The N2 and CO2 adsorption results indicate pores less than 3 nm in diameter are the major contributors to the specific surface area for shale, accounting for 80% of the total. In addition, micropores less than 2 nm in diameter are generated in large numbers during the thermal evolution of organic matter, which substantially increases the specific surface area and adsorption capacity. Competitive adsorption experiments prove that shale absorbs more CO2 than CH4, which implies that injection CO2 could enhance the CH4 recovery, and further research into N2 adsorption competitiveness is needed. The Langmuir model simulations indicate the shale gas adsorption occurs via monolayers. Geologically applying the adsorption potential model indicates that the adsorption capacity of shale initially increases before decreasing with increasing depth due to the combined temperature and pressure, which differs from the changing storage capacity pattern for free gases that gradually increase with increasing depth at a constant porosity. These two tendencies cause a mutual conversion between absorbed and free gas that favors shale gas preservation. During the thermal evolution of organic matter, hydrophilic NSO functional groups gradually degrade, reduce the shale humidity and increase the gas adsorption capacity. The shale quality, gas composition and geological conditions all affect the adsorption capacity. Of these factors, the clay minerals and humidity are less important and easily overshadowed by the other factors, such as organic matter abundance.  相似文献   

20.
India recognizes the strategic importance for developing shale gas resources like other countries in the world. Shale gas reservoirs are known to be difficult for extracting gas in comparison to conventional reservoirs. Recently, due to high prices of gas, rising demand and enhancement in recovery technologies has attracted the Indian energy industries to explore the shale gas resource. Coal and lignite are the prime source of energy in India and these resources are well explored, while shale is ignored, despite it being associated with coal and lignite bearing formations. The paper presents reservoir characteristics of shale horizons in Barren Measures and Barakar formations of north and south Karanpura coalfields. Shale core samples were collected from exploratory boreholes in air tight canisters. In-situ gas content and adsorption capacities ascertained to be 0.51–1.69 m3/t and 3.90–5.82 m3/trespectively. Desorbed gas derived from canisters contains CH4, C2H6, C3H8, CO2, N2 and O2 and varies from 76.19–82.63, 0.38–0.76, 0.10–0.50, 8.65–12.34, 9.89–19.34 and 0.56–2.24 vol. % respectively. The permeability and porosity determined under reservoir simulated confining pressure is varying from 0.41–0.75 mD and 0.89–2.28 % respectively. The plots of Rock Eval S2vs TOC and HI against Calc. VRo% indicates that all shale samples belong to Type III kerogen, which is prone to generate gas. It is evaluated that insitu gas content, sorption capacity, saturation level and low permeability of shale beds are critical parameters for development of shale gas resource in the studied area.  相似文献   

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