This study presents a systematic 3D physical simulation investigation of CO2 injection parameter sensitivity in deep saline aquifers, focusing on the synergistic effects of well type, injection rate, and geological barriers. Experiments conducted in a custom high-temperature, high-pressure 3D simulator with integrated resistivity tomography quantitatively tracked CO2 saturation evolution under controlled scenarios. Results indicate that horizontal wells increase dissolution trapping by 6.8% (absolute) relative to vertical wells under the tested conditions, an effect attributed to enhanced CO2-brine interfacial contact. Injection rate governs the trade-off between storage efficiency and operational safety: high-rate injection (4 mL/min) accelerates dissolution trapping to 26.6% but elevates near-wellbore pressure to an estimated level approaching the material's fracture threshold, suggesting a potential caprock fracturing risk under similar downhole conditions; low-rate injection (1 mL/min) promotes uniform plume distribution and enhances residual trapping, contributing to long-term storage stability. In this model, low-permeability barriers (1 × 10−5 mD) create hydraulically isolated pressure compartments that completely block vertical migration, enhancing local storage security, whereas moderate-permeability barriers (0.1 mD) permit partial breakthrough and cross-layer pressure communication. These findings provide a systematic 3D experimental dataset that illustrates multi-parameter synergy in CO2 storage under the specific conditions of a small closed-boundary laboratory model. For homogeneous reservoirs, the “horizontal well + medium-low injection rate” configuration performed best among the tested configurations in this specific closed-boundary laboratory model. Field-scale validation under open-aquifer conditions is required before any direct application.

The sealing capacity of fault zones, which fundamentally influences hydrocarbon migration and entrapment, is predominantly governed by their internal architecture. In sand-clay sequences, this capacity typically correlates positively with clay content. However, in the study area-the X492 trap bounding fault in the Huimin depression, Bohai Bay Basin of China, demonstrates effective sealing despite occurring in sand-rich sequences and having limited displacement. The reservoir description results showed that the height of the oil column sealed by this bounding fault reaches 30 m, and the clay content within the fault zone, as indicated by the Shale Gouge Ratio, is generally below 15%. To determine the cause, we studied the subcore of the fault zone surrounding the trap through observation and description. Core-based analysis of fault rocks reveals a sand-mud mixture with a mud-encased texture. Dense networks of deformation bands and laminated phyllosilicate fabrics, approximately 1 mm thick, display high continuity and no evidence of hydrocarbon invasion. Laboratory measurements show these fault rocks are clay-dominated with minimal carbonate cement (<5%). Thin-section and micro-CT analyses indicate that deformation bands and phyllosilicate layers reduce grain size by 0-2 orders of magnitude and porosity by 10-20% relative to the host rock, significantly degrading petrophysical properties. This millimeter-scale microstructure is interpreted as the key mechanism for subsurface fluid sealing. This study conducts an analysis based on the above and presents a discussion on the potential sealing mechanism of the bounding fault of a trap, proposing a sealing model for low-displacement faults developed in high net/gross sand ratio sequences. This study demonstrates that in specific scenarios, low-displacement faults possess sealing capabilities and exploration potential.

Deformation bands are a type of local strain concentration structure that develops in porous rocks, and they play an important role in the fluid dynamics of underground reservoirs. Although field outcrop observations can provide important information for revealing the geometry and distribution characteristics of deformation bands, capturing the dynamic processes and controlling mechanisms of deformation band formation and evolution is difficult. In recent years, laboratory-scale physical simulations have become key methods for studying the formation processes of deformation bands by precisely controlling stress, displacement, and material properties to reproduce the evolution path. In this study, the shear experiment methods, quantitative structural analysis techniques, and numerical simulation strategies that are widely used in the current research on deformation bands are systematically reviewed and evaluated. Physical simulation methods, such as ring shear, direct shear, triaxial shear, and sandbox experiments, and porosity and permeability measurement methods, which are based on computed tomography (CT) scans and image processing, are assessed in this paper. Furthermore, the ways that experimental data are used in the construction of parameters of discrete element and continuum models are discussed, as are modeling practices at the core and regional scales. Finally, the main challenges are summarized, including in situ permeability testing for consolidated rocks, the imperfection of quantitative structure analysis technologies, the difficulty in simulating the effects of cement, and the bottleneck in cross-scale modeling, and key directions for future research are proposed. The aim of this review is to establish a research framework that integrates experiments, calculations, and observations to provide theoretical and methodological support for an in-depth understanding of the formation mechanism of deformation bands and their control on underground fluid migration.

It is a common occurrence in the fracture processes of deep carbonate reservoirs that the fracturing construction pressure during hydraulic fracturing operation exceeds 80 MPa. The maximum pumping pressure is determined by the rated pressure of the pumping pipe equipment and the reservoir characteristics, which confine the fracture to the target area. When the pump pressure exceeds the safety limit, hydraulic fracturing has to reduce the construction displacement to prevent potential accidents caused by overpressure. Therefore, real-time prediction of the fracturing construction pressure and diagnosis of abnormal fluctuations during hydraulic fracturing of highly deviated wells are indispensable. Based on the well trajectory, pumping process, and string structure of highly deviated wells, a movement interface model for the fracturing fluid at different stages within the wellbore has been established, using the method of computational fluid dynamics. This model analyzes the fluid movement behavior with diverse properties at various fracturing times and determines the relationship between the pressure changes at the leading and trailing edges of fluid movement in each section of the wellbore over time by combining different string structures and preset pumping procedures. The frictional pressure within the wellbore fluid, the hydrostatic fluid pressure, and the near-well friction drags have been calculated and predicted. A real-time prediction model for diagnosing pumping fracturing has been constructed to further comprehend “abnormal” fracturing construction pressures in highly deviated wells. This offers a theoretical foundation for the correct diagnosis and decision-making regarding hydraulic fracturing in highly deviated wells while guiding its smooth implementation in real time.

The safe operation of underground gas storage (UGS) facilities is crucial for ensuring a stable gas supply, achieving seasonal peak shaving, and securing strategic energy reserves. Fault stability is, in turn, a critical to keeping the UGS integrity. Therefore, it is essential to assess the stability of faults in a UGS facility and determine the critical pressure for fault instability. In this study, we explore the stability of faults in the Lei 61 UGS facility within the Liaohe Basin. Conventional method that assumes the frictional coefficient of faults is a fixed value, tends to overestimate the fault stability, as shown by the research results. Given that clay minerals can reduce the frictional strength, we examine the relationships of clay minerals of various types with the frictional coefficient of faults. By integrating theoretical calculations with the experimental calibration of the frictional strength, we develop a model for quantitatively characterizing the heterogeneity in the frictional strength of faults tailored to the study area. This approach enhances the scientific rigor of fault stability assessment and enables a more accurate fault stability assessment for the Lei 61 UGS facility. According to the comparison of the assessment results, the conventional assessment method predicts that all faults in the UGS facility remain highly stable under the current stress field, at a minimum activation pressure of 20.04 MPa; in contrast, the improved assessment method indicates a minimum activation pressure of 16.68 MPa, with a decrease of 3.36 MPa, despite the absence of any fault activation.

Fault zones play a key role in controlling subsurface fluid migration, influencing hydrocarbon accumulation, CO2 sequestration, and geo-energy storage safety. Most previous experimental studies, however, have been restricted to static outcrop or core observations, which fail to capture the progressive evolution of fault zone structures in time as a response to changing stresses. Moreover, existing analogue experiments often use unconsolidated sediments, which cannot accurately represent brittle faulting in consolidated rocks, and quantitative analyses remain limited. To address these challenges, a new method based on ring-shear experiments was developed to physically simulate fault zone formation in consolidated sandstones. The method simulates shear deformation under variable stress and displacement conditions, followed by multi-scale quantitative analyses, including computed tomography imaging, thin section analysis, and porosity-permeability testing under confining pressure. This comprehensive testing routine allows to quantify changes in fault zone thickness, particle and pore size distributions, and grain orientations during progressive deformation and depending on shear parameters. The results demonstrate systematic relationships between effective normal stress, shear displacement, and fault zone structural attributes. The fault zone thickness shows a nonlinear trend with stress, while cataclasis and compaction intensify with increasing displacement. This work provides a methodological foundation for future applications in fault seal analysis, fluid flow modeling, and numerical simulation, offering a practical reference for petroleum systems studies, hydrogeology, and underground gas storage including CO2 and hydrogen.

The ability of faults to transport oil and gas is affected by multiple geological factors, and the effects of various factors on oil and gas migration and accumulation are complex. In this study, based on the drilling and three-dimensional seismic data in the No. 4 structural zone of the Nanpu Sag and by considering the effects of fault throw, caprock thickness, shale content, fluid pressure, stress normal to the fault plane, and brittleness, we employed fault transport index (FTI) to quantitatively characterize the vertical transport ability of regional faults. Through statistical analysis, fault transport probability (Np) was used to characterize the relationship between FTI and the vertical hydrocarbon content in the formations. The results show that the faults with FTI less than 0.75 cannot transport oil and gas, while those with FTI greater than 2.5 are able to transport oil and gas. Specifically, when FTI is between 0.75 and 2.5, there is a functional relationship between the probability of faults transporting hydrocarbons and FTI. The current oil and water distribution and paleo oil reservoir test results indicate that there are oil layers or paleo oil reservoirs in horizons with large Np. Therefore, FTI can be used as an effective coefficient to indicate the vertical migration paths and accumulation spots of hydrocarbons moving along faults, providing an essential reference for further oil and gas exploration and development.

Water injection in fault block oil and gas reservoirs can trigger fault activity, leading to leakage and potential earthquakes, which may cause significant natural and economic losses. The friction coefficient of the fault is a crucial factor in fault activity and stability. Analyzing this relationship is essential for evaluating fault stability. This study focuses on the Penglai fault zone in the Bohai Bay Basin, China, investigating the weakening mechanism of fault gouge on the friction coefficient and integrating key factors that control its heterogeneity. The friction strength of fault gouge was evaluated through circular shear experiments conducted under in situ geological conditions, establishing a method for characterizing the heterogeneity of friction strength. Based on these findings, a model for characterizing the heterogeneity of fault friction coefficients was developed. By integrating a 3D prediction model of clay content on fault surfaces, the spatial distribution of non-uniform friction coefficients across fault planes was determined. The research findings indicate a negative correlation between the steady-state friction coefficient and the maximum static friction coefficient with respect to fault shale content. Within a mud content range of 0% to 35%, the friction coefficient remains approximately constant at around 0.6 with minimal fluctuation. As the mud content increases from 35% to 40% to 65%, there is a gradual decrease in the friction coefficient, followed by a rapid decline when the mud content reaches 65% to 75%. This trend suggests an increased influence of mudstone on frictional sliding. As the mud content increases, leading to greater involvement of mudstone in frictional sliding, significant fluctuations in the friction coefficient are observed due to the combined effects of mudstone and quartz sandstone. Ultimately, when the mud content reaches 80% to 100%, the friction coefficient decreases further, with a reduced fluctuation range. This highlights the predominant role of shale content in influencing frictional sliding behavior. The method for characterizing fault-mud-content-related friction coefficients at various levels significantly enhances the accuracy of fault stability evaluations, thereby promoting the safe and efficient development of oil and gas reservoirs.

There are many factors that affect the faults sealing capacity, but the traditional lateral sealing model only considers the clay content, which leads to the great limitations of the established evaluation model. The objective of this study is to comprehensively examine the influence of potentially contributing factors on the fault sealing capacity. The Shuangtaizi structure is selected as the research focus in this study, where a 3D geological model is established to conduct detailed reservoir characterization for calculating trap elements and hydrocarbon column height. Subsequently, a dataset on the sealing attributes of fault-bounded traps is constructed after optimizing the dataset. By utilizing both machine learning evaluation models and traditional methods, the evaluation of the lateral sealing capacity of Shuangtaizi structural faults is performed. The influencing factors of fault rock sealing are clearly delineated as ten key parameters: effective normal stress, clay content, fault strike, fault throw, dip angle, transverse gradient, dip slip gradient, longitudinal gradient, longitudinal strain and shear strain in descending order of importance. Among these factors analyzed for fault sealing considerations, the most significant is the effective normal stress followed by clay content. By establishing a novel machine learning-based lateral sealing evaluation model and comparing it with the traditional SGR-AFPD fault lateral sealing evaluation model, it could be observed that the machine learning model exhibits a smaller error range and higher confidence in its evaluation results compared to the traditional model. Notably, the conventional model fails to consider the crucial influence of effective normal stress on sealing performance, which accounts for its inadequate accuracy. The model incorporates a comprehensive assessment of various factors that influence the lateral sealing capability of faults. In order to obtain objective and more realistic evaluation results, it is imperative to establish a multidimensional evaluation model in future studies.

In the hydraulic fracturing oil and gas reservoir, the temperature variation of the fracturing fluid has a great impact on its flow and rheology, affecting the sand-carrying capacity and friction resistance of the fracturing fluid, and also affecting the settling speed of proppant in the fracture, thus changing the sand setting profile and sand laying concentration, and finally affecting the geometry of the fracture. Based on the energy balance and continuity equations, a numerical model for the distribution of wellbore temperature field in an extended-reach well is developed, and a variation law for the wellbore and reservoir temperature fields during fracturing also is formulated. A 3D mathematical model of the temperature distribution in hydraulic fracture and near-fracture formations has been developed based on heat transfer theory and finite-difference methods, taking into account the temperature gradients of fracture length and height according to the energy balance principle and fracture fluid continuity equations. The sensitivity factors of the temperature field are clarified, the wellbore temperature field and the fracture matrix temperature field model are coupled, and the influence rule of the temperature field change of the construction layer on the fracture shape while fracturing is revealed, which provides a theoretical basis for the hydraulic fracturing design optimization.

As a crucial reserve for natural gas, the safe operation of underground gas storage facilities is paramount for seasonal peak shaving and emergency supply security. Focusing on the Lei X gas storage facility in the Liaohe Basin of China, this study delves into the mechanical integrity of gas storage facilities and assesses the upper limit pressure for safe operation. Leveraging seismic logging data, we conducted an analysis and statistical evaluation of boundary faults and top cover characteristics, integrating regional stress fields and rock mechanics to evaluate fault activation pressure and cover failure risk using a fault activation pressure assessment method. This research elucidates the maximum safe operating pressure for underground gas storage facilities. The research findings suggest that the sealing layer of the Lei X gas storage reservoir exhibits a predominant hydro-fracturing pattern. Under the existing stress field conditions, the sealing layer demonstrates favorable sealing properties, and the boundary faults remain relatively stable. Moreover, through data extraction and quantitative analysis, this study clearly determined the critical pressure at which each fault is activated and the pressure at which the sealing layer undergoes hydro-fracturing during cyclic injection and the production of gas storage. Considering the activation pressure and fracturing pressure data for the sealing layer, a secure operating pressure of 15.0 MPa was calculated for gas storage operations. This study offers crucial theoretical support for enhancing injection and production efficiency, as well as ensuring the safe operation of Lei X gas storage and providing technical guidance for future adjustments to injection and production schemes.

Investigating the deformation mechanism of cataclastic bands in high-porosity sandstone is crucial for understanding the juxtaposition sealing ability of sandstones in a bed sequence. However, deformation bands that are developed in the field and rock cores do not reflect the evolutionary history of the host rock; therefore, the continuous deformation of high-porosity sandstone cataclastic bands cannot be observed. This paper analyzes the deformation mechanism that affects a cataclastic band when high-porosity sandstone faults form. Based on the latest independently developed high-pressure/low-speed ring shear experimental apparatus, the formation and evolutionary process of cataclastic bands in high-porosity sandstone were studied through the similarities among artificial cores. During the experiments, the effective normal stresses and fault displacement were used as single variables. After the experiments, plunger samples were drilled in the lateral direction, and thin sections were prepared to observe and analyze the thickness and particle characteristics of the deformation bands, thereby characterizing the deformation process of the damage zone. The experimental results reveal that high-porosity sandstone undergoes different intensities of cataclasis during the shearing process, and the evolutionary characteristics can be divided into four primary stages. The particles in the sandstone are successively subjected to rotation, rolling, cracking, cataclasis, and other changes after forced deformation. In terms of the macrostructure, a deformation band can be divided into two layers: an inner zone and an outer zone. From the host rock and the outer zone to the inner zone, the orientational arrangement of the particles along the shear direction becomes increasingly clear, and a greater displacement indicates a stronger orientational arrangement effect of the particles. In terms of the microstructures, the particle sizes in the deformation band are 2–3 orders of magnitude smaller than those in the host rock and exhibit greater roundness. With increasing shear displacement, the thickness of the cataclastic band first increases and then remains constant. With increasing effective normal stress, the thickness first decreases slightly, then increases and finally decreases slightly. Therefore, stress and displacement are important factors controlling cataclasis. The influence of displacement on cataclasis is clear at the initial stage, and stress determines the maximum intensity of cataclasis. Additionally, the increase in displacement will be favorable for roundness when the host rock is poorly sorted. These experimental results provide a theoretical basis for future studies on the effects of cataclastic bands and fluid flow.

莺歌海盆地是我国南海重要的天然气探区.通过对莺歌海盆地中央坳陷带不同成藏体系典型气藏和含气构造的精细解剖,评价了盖层的有效性及控制因素,并分析了盖层对天然气成藏的控制作用.研究结果表明:①莺歌海盆地中央坳陷带浅层和超浅层成藏体系中,盖层的封盖有效性受到盖层、底辟构造及底辟构造活动伴生断裂的共同控制;中深层成藏体系中普遍存在异常高流体压力,且断裂不太发育,盖层水力封闭是控制油气差异富集的关键因素.②浅层和超浅层成藏体系内,脆性盖层保持封盖有效性的临界断接厚度为86～98 m;中深层成藏体系内,盖层的封盖有效性可以通过水力破裂压力系数进行评价,当系数大于1时,意味着盖层已发生破裂或具有极强的水力破裂的风险.③整体上中央坳陷带超压诱发的水力破裂是中深层盖层封闭失效的根本原因,深层天然气通过水力破裂通道运移至浅层,最终经断裂调整至超浅层成藏,气源充足的条件下,超浅层及浅层气藏主要集中分布在底辟的顶部,而中深层气藏主要集中分布于底辟翼部及斜坡区.

The hazards of fault reactivation caused by fluid injection are a growing concern. However, traditional evaluation methods of fault stability are likely to underestimate the risk in fault segments with a high clay content. Therefore, an extended evaluation method of fault stability (ECPP) incorporating the heterogeneity in friction strength caused by variation in the clay content within the fault zone is established in this study. After characterizing the current stress field of the BZ34-2 Oilfield in the Huanghekou Sag, Bohai Bay Basin, the reactivation potential of faults is evaluated using both traditional and ECPP methods. Traditional evaluation of fault stability shows that all faults are stable in the present stress field. Faults oriented ENE have a relatively high risk. The maximum sustainable fluid pressure Dp is approximately 8.8-8.9 MPa and 9.3-9.9 MPa. When considering the heterogeneity in fault friction strength, the fault stability is clearly controlled by the clay content of the faults. The high-risk fault segments assessed using traditional methods are no longer obvious, which reflects the importance of incorporating friction strength heterogeneity in the process of fault evaluation. Moreover, the results also show that most fault segments are activated when the fault zone is dominated by montmorillonite, reflecting the strong influence of clay mineral types on fault stability. The factors influencing the heterogeneity of fault friction strength are very complicated in actual situations. Therefore, future work should focus on establishing a database through a large number of experiments and investigating the relationship between the friction coefficient and the main controlling factors.(c) 2023 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/ 4.0/).

Mudstone is the most common cap rock in petroliferous basins. The mechanical properties of mudstone in different areas and buried depths are obviously different, which directly affects the brittleness and ductileness of caprock and its deformation characteristic. This research carried out X ray diffraction (XRD) rock mineral composition analysis, microscopic observation of mineral structural characteristics and rock mechanics triaxial compression tests under different conditions on six groups of mudstone samples from three basins. On this basis, establish numerical model to simulate the fracture deformation of mudstone under geological conditions, and to clarify the influence of different factors on the rock mechanics of mudstone. Compare and analyze the fracture characteristics and stress-strain curves of mudstone samples after the test show that, the confining pressure is the most direct factor affecting the mechanical properties and deformation mechanism of mudstone in the range of oil and gas enrichment depth. Although the formation temperature has a certain influence on the rock deformation, the effect is very limited, and it is difficult to have an essential influence on the rock deformation without the action of confining pressure. The mineral composition of mudstone is also one of the main factors affecting the mechanical deformation of rock. The comparison between the content of main minerals and the mechanical parameters of rock shows that the mechanical properties of rock and the transformation of brittleness and ductileness of mudstone have the most obvious correlation with clay minerals. Numerical simulations show that, pore fluid pressure is an important factor that cannot be ignored in overpressured caprocks. Higher pore fluid pressure can significantly inhibit the transition process of rock brittleness and ductileness, and at the same time affect the fracture mode of mudstone, which is of great significance for the evaluation of caprock integrity.

莺歌海盆地中央坳陷带油气富集区大断层不发育,底辟作用和天然水力破裂作用是油气纵向分布差异的核心控制因素.本文在地应力评价的基础之上以保持力为表征参数对典型区块浅层和中深层不同气组顶部盖层进行了水力破裂风险性分析,并结合底辟区和非底辟区气藏分布的差异性,明确了超压型盆地天然水力破裂作用对天然气成藏的意义,认为在气源充足的情况下底辟区具有更强的疏导油气的能力,而在非底辟区,油气只能以水力破裂的方式运移.研究结果表明:底辟区浅层气组保持力均大于0,中深层气组保持力大多小于0;而在非底辟区的中深层,气组保持力大多大于0.浅部地层超压程度相对较小,油气无法以水力破裂的方式在浅层运移,大部分通过底辟作用运移到底辟顶部成藏,浅层气藏主要集中在底辟顶部及底辟作用波及区域;中深层超压程度很高,烃源岩及砂体之间均可以通过水力破裂作用进行疏导油气,但在底辟区油气的疏导具有底辟和水力破裂双重作用:底辟活动期,底辟上拱形成张性伴生裂缝进行疏导油气的同时也大幅度降低了水力破裂的临界压力;底辟静止期,由于有先存伴生裂缝的存在而更容易发生水力破裂.

Production safety at the Shuang 6 gas storage facility is controlled by the fault block system underlying the facility. In this study, the “fault valve” theory, Coulomb fracture criterion, and current crustal stress conditions are considered as constraints for the Mohr’s circle stress calculation model, which is used to simulate and evaluate the fault stability beneath the facility. The stability margin of faults at the current maximum operating storage pressure and the formation fluid pressure (activation pressure) corresponding to fault activation are estimated, providing a basis for the upper limit of gas injection pressure for gas storage safety. The results show that the related internal faults at Shuang 6 gas storage are in a stable state under the current crustal stress and the highest gas storage pressure. The fault activation pressures of the Xing II and Xing III formations in the Shuangtaizi area exceed 8 MPa higher than the original formation pressures, and there is a large space available for additional gas storage capacity, including other regional storage groups.

在油气勘探过程中,对于小位移断层分隔油水封闭能力的控制因素研究尚浅,野外也难以获得不同变形过程的断层带结构及其渗透性变化规律.因此,以高孔隙度纯净砂岩人造岩心为研究对象,采用自主研发的"高压-低速环形剪切装置"开展实验,实验后样品取心分别进行覆压孔渗测试、纳米CT扫描、铸体薄片分析等分析测试.以有效正应力和断层位移为实验变量开展了多组环剪实验,其研究结果表明:宏观上断层面上可观察到明显擦痕与粉末状碎裂岩,微观上确定了断层带内碎裂作用导致的颗粒粒度降低与颗粒的定向排列是孔渗降低的主要原因,断层带渗透率小于10 mD,较母岩降低2～3个数量级.随着断层有效正应力或断层滑动位移增加,断层带碎裂程度增大且粒径和孔径减小,断层带厚度增大,孔隙度和渗透率逐渐减小.这一结果可为小位移断层侧向封闭能力与油气勘探领域的研究奠定理论基础.

The Yinggehai Basin is an important Cenozoic gas bearing basin in the South China Sea. With the gradual improvement of gas exploration and over-development in shallow layers, deep overpressured layers have become the main target for natural gas exploration. There are no large-scale faults in the strata above the Meishan Formation in the central depression, and hydraulic fracturing caused by overpressure in mudstone cap rocks is the key factor for the vertical differential distribution of gas. In this paper, based on the leak-off data, pore fluid pressure, and rock mechanics parameters, the Fault Analysis Seal Technology (FAST) method is used to analyze the hydraulic fracture risk of the main mudstones in the central depression. The results show that the blocks in the diapir zone have been subjected to hydraulic fracturing in the Huangliu cap rocks during the whole geological history, and the blocks in the slope zone which is a little distant from the diapirs has a lower overall risk of hydraulic fracture than the diapir zone. In geological history, the cap rocks in slope zone remained closed for a longer time than in diapir zone and being characterized by the hydraulic fracture risk decreases with the distance from the diapirs. These evaluation results are consistent with enrichment of natural gas, which accumulated in both the Yinggehai Formation and Huangliu Formation of the diapir zone, but it only accumulated in the the Huangliu Formations of the slope zone. The most reasonable explanation for the difference of the gas reservoir distribution is that the diapirs promote the development of hydraulic fractures: (1) diapirism transfers deep overpressure to shallow layers; (2) the small fault and fractures induced by diapir activities weakened the cap rock and reduced the critical condition for the natural hydraulic fractures. These effects make the diapir zone more prone to hydraulic fracturing, which are the fundamental reasons for the difference in gas enrichment between the diapir zone and the slope zone.

油气区断层再活动会造成过断层井的井壁不稳定,增加生产井剪切套损风险及油气渗漏风险甚至诱发地震.浅埋断层带中广泛发育的断层泥对断层摩擦滑动具有重要影响,在特定地质条件下断层泥对断层带摩擦强度具有显著的弱化作用.传统的断层稳定性评价方法多数采用断层摩擦强度的均质模型.然而大量研究表明,断层泥受多种因素的影响在空间上表现出明显的非均质特征,如何对油气区断层泥摩擦强度非均质性进行定量表征,实现更精确的断层稳定性评价,对降低油田开发风险具有实际意义.文中介绍了断层带摩擦强度研究的原理、方法,通过梳理国内外的最新研究进展,从内因和外因两个角度详细总结了不同条件下断层泥变形机制以及摩擦强度的演化规律,其中内因包括黏土矿物类型以及黏土矿物含量,外因包括孔隙流体、有效正应力以及温度.同时,基于断层带摩擦强度的理论研究成果以及当前国际上常用的断层稳定性评价方法,建立了考虑断层摩擦强度非均质性的断层稳定性定量评价模型.最后,对断层带摩擦强度研究的未来发展趋势进行了分析.