陆相页岩储层发育多种类型、数量庞大且分布随机的天然裂缝系统，影响着勘探过程中三维地质建模的不确定性、钻井过程中井壁的稳定性和压裂开采过程中缝网形成的复杂性等问题，制约了陆相页岩油气的安全、高效开发。然而，何种天然裂缝、如何影响井壁稳定及缝网形成是亟需解决的难点，而开展天然裂缝表征及力学行为研究是解决这一问题的关键。因此，本文针对陆相页岩储层开展天然裂缝表征及力学行为研究，得到的结论和认识如下：

（1）陆相页岩储层天然裂缝定量表征研究

提出了基于分形拓扑理论并结合统计学方法的陆相页岩储层天然裂缝定量表征新方法，通过分形维数、拓扑节点类型、拓扑结构参数和裂缝产状对天然裂缝发育程度、类型、连通性及分布进行定量表征。①天然裂缝整体发育程度较低，且分形特征较差；②天然裂缝共分为I型、II型和III型节点天然裂缝三类；③天然裂缝网络主要由I型节点主导，天然裂缝连通性较差；④I型、II型和III型节点天然裂缝分别在与最大水平主应力夹角10°、5°、5°方向分布。

（2）典型天然裂缝发育陆相页岩储层井周应力分布研究

建立了天然裂缝发育陆相页岩储层直井和水平井井周三维应力分布新模型，利用有限元法揭示了边界地应力加载条件下典型天然裂缝发育陆相页岩储层井周应力分布特征及典型天然裂缝对井周应力的影响。①周向应力、径向应力在各向同性储层直井井周呈正交对称分布，在横向各向同性储层直井井周呈非正交非对称分布，在各向同性和横向各向同性储层水平井井周呈非正交非对称分布，切向应力分布杂乱；②水平井相对直井近井井周应力值和应力集中程度大，水平井井壁最不稳定；③天然裂缝对近井井周应力影响较大，对远场应力影响较小，其中，II型和III型节点天然裂缝对于井周周向应力、径向应力和切向应力影响最为显著，井壁最不稳定。

（3）典型天然裂缝发育陆相页岩储层水力压裂裂缝力学行为研究

通过物理模拟，并结合数值模拟首次明确了水力压裂条件下水平井横向和垂向陆相页岩储层典型天然裂缝群影响下水力裂缝起裂和扩展规律以及其与典型天然裂缝相互作用机制。①I型节点天然裂缝发育储层水力压裂裂缝起裂位置呈对称式，而II型和III型节点天然裂缝发育储层水力压裂裂缝起裂位置呈非对称式；②II型节点天然裂缝对水力裂缝扩展的诱导能力最强，III型节点天然裂缝次之，I型节点天然裂缝诱导能力最低；③水力裂缝与典型天然裂缝相互作用时未能穿过天然裂缝，在裂缝相交点处开启天然裂缝，其中，II型和III型节点天然裂缝开启的天然裂缝分支多于I型节点天然裂缝，并沿着开启的天然裂缝转向延伸。

（4）典型天然裂缝发育陆相页岩储层水力压裂效果优化研究

基于单因素分析和正交试验，利用有限元分析法首次揭示了压裂施工参数对水平井横向和垂向陆相页岩储层典型天然裂缝群影响下裂缝力学行为的影响，并通过压裂后缝网复杂程度和水力裂缝长度确定了影响裂缝力学行为的主要、次要因素及最优压裂施工方案。①压裂液排量、黏度和地应力差过高过低都会抑制水力裂缝扩展，且无法有效开启天然裂缝或层理，降低压裂效果；②水平井横向I、II和III型节点天然裂缝发育储层最优压裂液排量为0.015m³/s，最优压裂液黏度分别为0.009Pa·s、0.001Pa·s和0.005Pa·s，最优地应力差分别为6×10⁶Pa、6×10⁶Pa和9×10⁶Pa；水平井垂向I、II和III型节点天然裂缝发育储层最优压裂液排量为0.015m³/s，最优压裂液黏度分别为0.001Pa·s、0.009Pa·s和0.009Pa·s，最优地应力差分别为6×10⁶Pa、3×10⁶Pa和6×10⁶Pa；③水平井横向典型天然裂缝发育储层压裂液排量是影响裂缝力学行为的主要因素，压裂液黏度次之，地应力差最小。水平井垂向I型节点天然裂缝发育储层压裂液排量是影响裂缝力学行为的主要因素，压裂液黏度次之，地应力差最小，而II和III型节点天然裂缝发育储层压裂液排量是影响裂缝力学行为的主要因素，地应力差次之，压裂液黏度最小；④水平井横向I、II和III型节点天然裂缝发育储层最优压裂施工参数组合分别为0.015m³/s、0.001Pa·s和6×10⁶Pa，0.015m³/s、0.001Pa·s和9×10⁶Pa，0.015m³/s、0.005Pa·s和9×10⁶Pa，水平井横向I、II和III型节点天然裂缝发育储层最优压裂施工参数组合分别为0.015m³/s、0.005Pa·s和6×10⁶Pa，0.015m³/s、0.009Pa·s和3×10⁶Pa，0.015m³/s、0.001Pa·s和9×10⁶Pa。

本论文的研究可为陆相页岩油气安全、高效开发方案的制定提供理论和技术指导。

Continental shale reservoirs have various types of natural fracture systems with a large number and random distribution, which affects the uncertainty of 3D geological modeling, the wellbore stability and the complexity of hydraulic fracture network formation in the process of exploration, drilling and production. These restrict the safe and efficient development of continental shale oil and gas. However, what type of natural fractures and how it affects wellbore stability and fracture network formation are the difficult problems to be solved urgently. The study of natural fracture characterization and mechanical behavior in continental shale reservoirs is the key to solve this problem. Therefore, natural fracture characterization and mechanical behavior of continental shale reservoir are studied in this paper, and the conclusions and understandings are as follows.

(1) Quantitative characterization of natural fractures in continental shale reservoirs

A new method for quantitative characterization of natural fractures in continental shale reservoirs based on fractal theory, topology theory and statistical method was proposed. The development degree, type, connectivity and distribution of natural fractures were characterized by fractal dimension, topological node type, topological structure parameters and fracture occurrence quantitatively. Firstly, the overall development degree of natural fractures is low and the fractal characteristics are poor. Secondly, the natural fractures can be divided into three types: natural fractures with type I nodes, natural fractures with type II nodes and natural fractures with type III nodes. Thirdly, the natural fracture network is mainly dominated by type I nodes, the connectivity between natural fractures is poor. Fourthly, natural fractures with type I, II and III nodes are distributed at angles of 10°, 5° and 5°with the direction of maximum horizontal principal stress, respectively.

(2) Stress distribution around wellbore in continental shale reservoirs with typical natural fractures

New three-dimensional stress distribution models around vertical and horizontal wellbores were established in shale reservoirs with natural fractures, the finite element method was used to analyze stress distribution around wellbore in continental shale reservoir with typical natural fractures and the effect of typical natural fractures on the stress around the wellbore under boundary in-situ stress. And wellbore stability and the prediction of whether hydraulic fractures can be initiated on wellbore wall was carried out. Firstly, circumferential stress and radial stress are distributed orthogonally and symmetrically around vertical wellbore in isotropic reservoirs, but they are distributed non-orthogonally and asymmetrically around vertical wellbore in laterally isotropic reservoirs, circumferential stress and radial stress are distributed non-orthogonally and asymmetrically around horizontal wellbore in isotropic and laterally isotropic reservoirs, and the tangential stress distribution is disordered. Secondly, stress value and its stress concentration degree near horizontal wellbore are larger compared with vertical well, and borehole wall of horizontal wellbore is the most unstable. Thirdly, natural fractures have a greater effect on the near-wellbore stress, but less on the far-field stress. Natural fractures with type II and type III nodes have the greatest effect on circumferential stress, radial stress and tangential stress around wellbore, borehole wall is the most unstable.

(3) Fractures mechanical behavior in continental shale reservoirs with typical natural fractures

Through physical simulation, combined with numerical simulation, the law of hydraulic fracture initiation and propagation under the influence of typical natural fracture groups, and also the interaction mechanism between hydraulic fracture and typical natural fractures were clarified for the first time in horizontal and vertical direction of horizontal wells of continental shale reservoirs. Firstly, the initiation position of the hydraulic fracture is symmetrical in naturally fractured reservoir with type I nodes, while the initiation position is asymmetrical in naturally fractured reservoir with type II and type III nodes. Secondly, natural fractures can induce hydraulic fracture propagation, among which natural fractures with type II nodes have the strongest inducing ability to hydraulic fracture propagation, followed by natural fractures with type III nodes, and natural fractures with type I nodes have the weakest inducing ability under the influence of typical natural fracture groups. Thirdly, hydraulic fracture fails to pass through the natural fractures, but opens the natural fracture at the intersection of the fractures. Among them, natural fractures with type II and type III nodes open more fracture branches than natural fractures with type I nodes, and then turns and extends along the opened natural fracture when hydraulic fractures interact with natural fractures.

(4) Fracturing effect optimization in continental shale reservoirs with typical natural fractures

Finite element analysis method was used to reveal the effect of fracturing parameters on mechanical behavior of fractures under typical natural fracture groups in horizontal and vertical direction of horizontal well of continental shale reservoirs based on single factor analysis and orthogonal experimental design, then the main and secondary factors affecting the mechanical behavior of fractures and the optimal fracturing scheme were determined by the complexity of fracture network and hydraulic fracture length. Firstly, too high or too low fracturing fluid displacement, fracturing fluid viscosity and ground stress difference will inhibit hydraulic fracture propagation, hydraulic fractures cannot effectively open natural fractures or beddings, which reduce the fracturing effect. Secondly, the optimal fracturing fluid displacements respectively are 0.015m³/s, 0.015m³/s, and 0.015m³/s, the optimal fracturing fluid viscosities respectively are 0.009Pa·s, 0.001Pa·s, and 0.005Pa·s, and the optimal in-situ stress differences respectively are 6×10⁶Pa, 6×10⁶Pa and 9×10⁶Pa for hydraulic fracturing in horizontal direction of horizontal well in naturally fractured reservoirs with type I nodes, type II nodes and type III nodes. For hydraulic fracturing in vertical direction of horizontal well in naturally fractured reservoirs with type I nodes, type II nodes and type III nodes, the optimal fracturing fluid displacements respectively are 0.015m³/s, 0.015m³/s, and 0.015m³/s, the optimal fracturing fluid viscosities respectively are 0.001Pa·s, 0.009Pa·s, and 0.009Pa·s, and the optimal in-situ stress differences respectively are 6×10⁶Pa, 3×10⁶Pa and 6×10⁶Pa. Thirdly, for hydraulic fracturing in horizontal direction of horizontal well in naturally fractured reservoirs with type I nodes, type II nodes and type III nodes, fracturing fluid displacement is the main factor affecting fracture mechanical behavior, followed by fracturing fluid viscosity, and the in-situ stress difference is the least. For hydraulic fracturing in vertical direction of horizontal well in naturally fractured reservoirs with type I nodes, fracturing fluid displacement is the main factor affecting fracture mechanical behavior, followed by fracturing fluid viscosity, and the in-situ stress difference is the least. However, in naturally fractured reservoirs with type II nodes and type III nodes, fracturing fluid displacement is the main factor affecting fracture mechanical behavior, followed by in-situ stress difference, and the fracturing fluid viscosity is the least. Fourthly, the optimal combinations of fracturing operation parameters in horizontal direction of horizontal well are 0.015m³/s, 0.001Pa·s and 6×10⁶Pa in naturally fractured reservoir with type I nodes, 0.015m³/s, 0.001Pa·s and 9×10⁶Pa in naturally fractured reservoir with type II nodes, 0.015m³/s, 0.005Pa·s and 9×10⁶Pa in naturally fractured reservoir with type III nodes. Meanwhile, the optimal combinations of fracturing operation parameters in horizontal direction of horizontal well are 0.015m³/s, 0.005Pa·s and 6×10⁶Pa in naturally fractured reservoir with type I nodes, 0.015m³/s, 0.009Pa·s and 3×10⁶Pa in naturally fractured reservoir with type II nodes, 0.015m³/s, 0.001Pa·s and 9×10⁶Pa in naturally fractured reservoir with type III nodes.

The research in this paper can provide theoretical and technical guidance for the safe and efficient development scheme of continental shale oil and gas.