Based on the theory of damage mechanics,a numerical model of reservoir flow-stress-damage cou-pling fracture propagation was established,and it was verified by comparing with inddor true triaxial hydraulic fracturing physical simulation experiment results.What's more,the influences of fracturing fluid viscosity,dis-placement,horizontal stress difference and reservoir rock heterogeneity on in-fracture temporary plugging and di-verting fracturing were discussed.The results show that:(1)The numerical model of reservoir flow-stress-damage coupling fracture propagation is a combination of fluid flow control equation and rock deformation equa-tion to form an overall control equation,and the temporary plugging in the fracture can be simulated by artifi-cially setting high-strength rock physical and mechanical parameters and small reservoir permeability values in a certain area along the initial fracture propagation path.(2)The numbers of branch fractures,area of main frac-tures,and extension direction of main fracture in numerical simulation of in-fracture temporary plugging and di-verting fracturing fracture propagation model are basically consistent with the results of indoor true triaxial hy-draulic fracturing physical simulation experiment results.This model can achieve the simulation of matrix frac-ture and new fracture extension after temporary plugging in fractures,and also has a good simulation effect on the situation of in-fracture temporary plugging and diverting fracturing fracture propagation.(3)The larger the viscosity and displacement of fracturing fluid,the greater the length,reconstruction area and deflection angle of in-fracture temporary plugging and diverting fracturing fracture,and single fractures gradually transition to com-plex fractures.When the horizontal stress difference is less than 7.5 MPa,the effect of in-fracture temporary plugging and diverting fracturing is better.When the horizontal stress difference is 10-15 MPa,the fracturing ef-fect deteriorates.When the horizontal stress difference is greater than 15 MPa,the fractures hardly deflect.Reser-voir heterogeneity can affect the local propagation path of fractures,but has little impact on the overall propaga-tion trend of fractures.
水力裂缝的分布规律对致密砾岩油藏高效开发至关重要.通过对玛湖凹陷已压裂砾岩油区的水平取心井MaJ02 井的岩心裂缝观察,剖析了玛湖凹陷三叠系百口泉组致密砾岩储层中水力裂缝的类型、产状、组系、开度、密度及支撑剂充填情况,明确了其分布特征,并探讨了其形成机制.研究结果表明:①玛湖凹陷MaJ02 井百口泉组岩心中发育的水力裂缝条数占总裂缝数的 77.6%,走向为 90°～110°,倾角为 70°～90°.②研究区主要发育以走滑机制形成的剪切缝,占比为 65.8%,其次为张应力形成的张性缝,占比为 34.2%.剪切缝多成组出现,开度较小,多为全充填,裂缝面以"穿砾"为主,多条裂缝叠加而形成缝网破碎带;而张性缝多为单条出现,开度相对较大,裂缝面不规则,为全充填或半充填,裂缝面以"绕砾"为主.③研究区取心井与已压裂井距离越小,压裂段射孔簇间距越小,水力裂缝密度越大.在压裂工程条件相同的情况下,泥质支撑漂浮砾岩相和前缘席状砂微相的裂缝相对发育,砂质含量越高,水力裂缝密度越大.
根据地震、钻井及薄片等资料,采用地震波阻抗储层反演技术,对滨里海盆地东缘石炭系盐下碳酸盐岩储层特征、油气成藏规律进行了研究,并指出了下一步风险勘探方向.研究结果表明:①滨里海盆地东缘石炭系盐下碳酸盐岩储层可分为灰岩类、云岩类、云灰岩/灰云岩类、硅化硅质岩类等,储层孔隙度为 4%～12%,渗透率通常小于 1 mD,属于低—中孔、低渗孔洞-孔隙型储层.②研究区阿克若尔构造带主要发育岩性油气藏,无统一油水界面,油层呈薄层状分散分布,对比性和连续性均较差,优质储层多为高频三级层序旋回中上部的高生长率滩体及不整合面附近的岩溶储层.③采用基于层位-测井约束的初始模型的地震波阻抗储层反演技术预测碳酸盐岩薄储层,可更清晰地呈现KT-Ⅰ和KT-Ⅱ油层组储层的纵、横向展布特征.研究区有利储层主要发育在KT-Ⅱ油层组顶部的G1 和G4小层.
以钻井、测井及三维地震资料等为基础,通过岩心分析、连井对比、油气运聚模拟、地震反演及多信息叠合等方法,从油源条件、储-盖组合和输导体系 3 个方面对南苏丹境内Melut和Muglad 2 个裂谷盆地源上构造-岩性油藏成藏的主控因素进行了分析,并探讨了成藏模式.研究结果表明:①Melut和Muglad盆地均发育早白垩世第Ⅰ裂陷期优质烃源岩,厚度大、面积广、有机质类型好、成熟度适中,具有良好的油源条件;Melut盆地古近系Yabus组、新近系Jimidi组和Muglad盆地白垩系Aradeiba组发育三角洲相和河流相沉积,河道和水下分流河道微相砂体的含砂率、砂岩厚度均适中,且不同层序内河道的河型存在垂向演化,发育泛滥平原和水下分流间湾微相局部封隔带,形成多套源上砂泥互层储-盖组合,为形成规模构造-岩性圈闭提供了条件;边界控盆断裂与盆缘斜坡区控凹断裂是沟通主力烃源岩与源上目的层的主要油气垂向运移通道,源上层段发育的多期不整合面和富砂地层形成了多个侧向优势运移路径(输导脊),油源断裂与输导脊耦合控制Melut和Muglad盆地源上构造-岩性油藏的有利区带.②Melut盆地Yabus组、Jimidi组以及Muglad盆地Aradeiba组具备形成源上规模构造-岩性油藏的石油地质条件,成藏模式可分为"断裂垂向运移型"、"断裂垂向运移-不整合面侧向输导型"和"断裂垂向运移-连通砂体侧向输导型"3种.
为规范海外石油储量评估,提出海外岩性油气藏储量分类分级、岩性边界、含油面积及有效厚度确定的方法.研究结果表明:①海外P类储量一般必须具有公司或资源国政府批准的开发方案.P1 储量以具有商业产量或具商业测试流量的井为计算单元,其面积通常由生产井的泄油面积和已知气底或已知油顶与已知油底限定的范围确定.P1 储量边界到其与岩性边界一半距离范围内的储量为P2 储量;P2储量边界到岩性边界范围内的储量为P3 储量,如圈闭内没有或尚不能确定油水界面,则P3 储量应以圈闭溢出点来确定;如岩性或储层物性变化较剧烈,P2 储量可按P1 储量外推 1 个开发井距确定,P3 储量可按P2 储量外推 1 个开发井距确定.②当P类储量井到渗透储层尖灭线的距离不大于 3～4倍开发井距时,对于中—高孔渗储层,尖灭线可直接确定为岩性边界;对低孔渗储层,可将达到P类储量标准的最小有效厚度等值线确定为岩性边界.由岩性边界、油气水边界、致密层封堵带等综合圈定含油气面积,面积内的井应达到P类储量标准.已查明流体界面的油气藏,用于圈定含油气面积的流体界面应经钻井取心资料或测试资料证实;未查明流体界面的油气藏,应以测试证实的最低的出油气层底界或有效厚度值外推圈定含油气面积.③P1 储量有效厚度的确定应具有可靠的地层测试资料或充分的测井资料,并证实其具有一定的生产能力;P2 储量有效厚度的确定通常缺乏结论性的测试资料,并且未证实其生产能力;P3 储量的有效厚度存在较大的不确定性,因其在岩石物理解释方面存在不确定性.④推荐采用容积法开展岩性油气藏的储量评估,厄瓜多尔TP油田的实例证实了岩性油气藏储量分类分级和储量评估方法的有效性.
