Hydrocarbon migration and accumulation along the fault intersection zone-a case study on the reef-flat systems of the No.1 slope break zone in the Tazhong area, Tarim Basin

Understanding hydrocarbon migration and accumulation mechanisms is one of the key scientif ic problems that should be solved for effective hydrocarbon exploration in the superimposed basins developed in northwest China. The northwest striking No.1 slope break zone, which is a representative of superimposed basins in the Tarim Basin, can be divided into five parts due to the intersection of the northeast strike-slip faults. Controlled by the tectonic framework, the types and properties of reservoirs and the hydrocarbon compositions can also be divided into five parts from east to west. Anomalies of all the parameters were found on the fault intersection zone and weakened up-dip along the structural ridge away from it. Thus, it can be inferred that the intersection zone is the hydrocarbon charging position. This new conclusion differs greatly from the traditional viewpoint, which believes that the hydrocarbon migrates and accumulates along the whole plane of the No.1 slope break zone. The viewpoint is further supported by the evidence from the theory of main pathway systems, obvious improvement of the reservoir quality （2-3 orders of magnitude at the intersection zone） and the formation mechanisms of the fault intersection zone. Differential hydrocarbon migration and entrapment exists in and around the strike- slip faults. This is controlled by the internal structure of faults. It is concluded that the more complicated the fault structure is, the more significant the effects will be. If there is a deformation band, it will hinder the cross fault migration due to the common feature of two to four orders of magnitude reduction in permeability. Otherwise, hydrocarbons tend to accumulate in the up-dip structure under the control of buoyancy. Further research on the internal fault structure should be emphasized.

A Study of the Migration and Accumulation Efficiency and the Genesis of Hydrocarbon Natural Gas in the Xujiaweizi Fault Depression

In order to investigate the migration and accumulation efficiency of hydrocarbon natural gas in the Xujiaweizi fault depression, and to provide new evidence for the classification of its genesis, a source rock pyrolysis experiment in a closed system was designed and carried out. Based on this, kinetic models for describing gas generation from organic matter and carbon isotope fractionation during this process were established, calibrated and then extrapolated to geologic conditions by combining the thermal history data of the Xushen-1 Well. The results indicate that the coal measures in the Xujiaweizi fault depression are typical ＂high-efficiency gas sources＂, the natural gas generated from them has a high migration and accumulation efficiency, and consequently a large-scale natural gas accumulation occurred in the area. The highly/over matured coal measures in the Xujiaweizi fault depression generate coaliferous gas with a high δ^13C1 value （〉 -20‰） at the late stage, making the carbon isotope composition of organic alkane gases abnormally heavy. In addition, the mixing and dissipation through the caprock of natural gas can result in the negative carbon isotope sequence （δ^13C1 〉δ^13C2 〉δ^13C3 〉δ^13C4） of organic alkane gases, and the dissipation can also lead to the abnormally heavy carbon isotope composition of organic alkane gases. As for the discovery of inorganic nonhydrocarbon gas reservoirs, it can only serve as an accessorial evidence rather than a direct evidence that the hydrocarbon gas is inorganic. As a result, it needs stronger evidence to classify the hydrocarbon natural gas in the Xujiaweizi fault depression as inorganic gas.

Features and dynamic mechanisms of Cenozoic tectonic migration and its impact on the hydrocarbon accumulation in the northern South China Sea

The northern continental margin of the South China Sea （SCS） is located within the tectonic system of Southeast Asia, an area with a great deal of tectonic migration due to the regional tectonic movements. The available geological and geophysical data of the area are comprehensively analyzed in order to demonstrate the typical migration patterns of the Cenozoic tectonics in the northern SCS caused by the episodes of the Cenozoic tectonic movement. Furthermore, the lateral variation characteristics of the strata and the differ- ent evolution patterns of the main basins＇ features are assessed. It primarily focus on： （1） the Cenozoic epi- sodic rifting from north to south in the continental margin of the northern SCS; （2） the rifting and depression time of the main basins progressively become younger as one goes from north to south, signifying that the migration of both the tectonics and the sediments within the northern SCS travelled from north to south during the Cenozoic; and （3） the lateral tectonic migration on the direction of EW is not regular in total, but in some local areas the trending of the tectonic migration is from west to east. The analysis of the tectonic migration features of the northern SCS, in combination with the regional tectonic evolution background, indicates that the observed remote lagging effect, resulted from the India-Eurasia plate collision, is the main dynamic mechanism involved in the tectonic migration within the northern SCS. The tectonic migration has significant influence on both the organization of petroleum deposits and on the hydrocarbon accumulation within the basins in the northern SCS; comprehensive understanding of this dynamic system is of great reference value in predicting the hydrocarbon accumulation and has the potential to have an enormous impact in discovering new deep reservoirs for the future oil-gas exploration.

Artificial Neural Network Model of Hydrocarbon Migration and Accumulation

Based on the dynamic simulation of the 3 D structure the sedimentary modeling, the unit entity model has been adopted to transfer the heterogeneous complex passage system into limited simple homogeneous entity, and then the traditional dynamic simulation has been used to calculate the phase and the drive forces of the hydrocarbon , and the artificial neural network(ANN) technology has been applied to resolve such problems as the direction, velocity and quantity of the hydrocarbon migration among the unit entities. Through simulating of petroleum migration and accumulation in Zhu Ⅲ depression, the complex mechanism of hydrocarbon migration and accumulation has been opened out.

Paleoporosity and critical porosity in the accumulation period and their impacts on hydrocarbon accumulation—A case study of the middle Es3 member of the Paleogene formation in the Niuzhuang Sag, Dongying Depression, Southeastern Bohai Bay Basin, East Chi

Similar reservoir sandbodies and fault conduit systems in the sandstone reservoirs in the middle Es3 member of the Niuzhuang Sag have been problematic for a long time. The following problems remain unsolved： 1） The distribution of sandstone porosity is inconsistent with the hydrocarbon accumulation. The oil sandstones have low porosity instead of high porosity. 2） Sandstones, which have the same properties, have different levels of oiliness, and the sandstones with almost the same properties show different degrees of oil-bearing capacity. This study analyzes the condition of reservoirs in the research area during the accumulation period in terms of paleoporosity estimation and discusses the critical porosity of the sandstone reservoirs during the same period. The following conclusions can be drawn from the results. 1） Although reservoir properties are low at present and some reservoirs have become tight, the paleoporosity ranging from 18% to 25% is greater than the critical porosity of 13.9%. As the： loss of porosity is different in terms of burial history, the present porosity cannot reflect porosity during the accumulation period. Similar/y, high porosity during the accumulation period does not indicate that tbe present porosity is high. 2） The present reservoir location is consistent with the distribution of high paleoporosity during the accumulation period. This result indicates that high porosity belts are prone to hydrocarbon accumulation because of the dominant migration pathways generated as a result of property discrepancies under similar fault conduit conditions. Consequently, the hydrocarbon mainly accumulates in high porosity belts. Paleoporosity during the accumulation period is found to be a vital controlling factor. Therefore, high paleoporosity sandstones in the middle Es3 member of the Niuzhuang Sag have great potential for future exploration.

Hydrodynamic Evolution and Hydrocarbon Accumulation in the Dabashan Foreland Thrust Belt,China

There are two plays in the Dabashan foreland tectonic belt： the upper and the lower plays. The lower play experienced one sedimentary hydrodynamic stage, two burial hydrodynamic stages, two tectonic hydrodynamic stages and two infiltration hydrodynamic stages from the Sinian to the Cenozoic, while the upper play had one sedimentary hydrodynamic stage, one burial hydrodynamic stage, two tectonic hydrodynamic stages and one infiltration hydrodynamic stage from the Permian to the Cenozoic. Extensive flows of both sedimentary water, including hydrocarbons, and deep mantle fluid occurred in the Chengkou faults during collision orogeny in the Middle-Late Triassic Indosinian orogeny, and fluid flow was complicated during intracontinental orogeny in the Middle-Late Jurassic. In addition to these movements, infiltration and movement of meteoric water took place in the Chengkou faults, whereas in the covering-strata decollement tectonic belt, extensive sedimentary water flow （including hydrocarbons） occurred mainly in the Zhenba and Pingba faults. During the stage of rapid uplift and exhumation from the Cretaceous to the Cenozoic, the fluid flow was characterized mainly by infiltration of meteoric water and gravity-induced flow caused by altitude difference, whereas sedimentary water flow caused by tectonic processes was relatively less significant. Sedimentary water flow was more significant to the lower play in hydrocarbon migration and accumulation during collision orogeny in the Middle-Late Triassic Indosinian orogeny, but its influence is relatively slight on the upper play. On one hand, hydrodynamics during intracontinental orogeny in the Middle-Late Jurassic adjusted, reformed or oven destroyed oil reservoirs in the lower play; on the other hand, it drove large amounts of hydrocarbons to migrate laterally and vertically and is favorable for hydrocarbon accumulation. Infiltration hydrodynamics mainly adjusted and destroyed oil reservoirs from the Cretaceous to the Cenozoic.

The characteristics of unconformity surface at the bottom of the Paleogene and its significance in hydrocarbon migration in the Sikeshu Sag of the Junggar Basin, Northwest China

The unconformity surface at the bottom of the Paleogene, located in the Sikeshu Sag of the Junggar Basin, Northwest China, is one of the most important hydrocarbon migration pathways and characterized by 3 layers of upper coarse clastic rock, lower weathering crust and leached zone. The upper coarse clastic rock displays features of higher density, lower SDT and gamma-ray logging while the weathering crust in the lower part displays opposite features. The formation water is of NaHCO 3 type but at lower mineralization degree. The QGF indices are generally between 2.19 and 3.77 and the GOI parameters vary from 1% to 5%. From the southeast to the northwest of the sag, the content of saturated hydrocarbon increases from 30.81% to 53.74% while that of non-hydrocarbon and asphaltene decreases. The Pr/nC 17 decreases from 0.65 to 0.47 while the Ph/nC 18 decreases from 0.66 to 0.27, and the content of benzo[c] carbazole declines while the benzo[a] carbazole amount and (alkyl carbazole)/(alkyl+benzo carbazole) ratio both increase. These revealed that the hydrocarbons migrated from the sag to the ramp region along the unconformity surface.

Control effect of fluid entry pressure on hydrocarbon accumulation

The micromigration of oil-drive-water and gas-drive-water in oil and gas fields was studied,by using core slices and micro-experimental technology,and the migration processes and characteristics of oil and gas in pores and throats were observed,as well as entry pressures of oil/gas migration.Research shows that entry pressures of both oil-drive-water and gas-drive-water increase obviously as porosity decreases,and the statistical regularity observes the power function variation.However,there is a complex changing relationship between porosity and different entry pressure values of the two replacement processes,forming three curve sections,each representing a different accumulation significance.When the porosity is over 10%-12%,the difference between oil-drive-water and gas-drive-water entry pressures is small.Both oil and gas can migrate and accumulate in this kind of reservoir.The probabilities of oil and gas reservoir formation are nearly equal,forming conventional oil/gas pools.When porosity is between 5% and 10%-12%,the difference between the two is obvious,which indicates that this kind of reservoir can seal oil,but can also be a reservoir for gas,easily forming unconventional hydrocarbon pools(deep-basin gas pools).When porosity is less than 5%,the difference is indistinct and the entry capillary pressures show the same sealing function for oil and gas.In this condition,both oil and gas pools are difficult to form.Experimental results give a rational explanation for the difference of accumulation probability between deep-basin gas and deep-basin oil,and also for the mechanism of tight sand acting as cap rock.

Tight sandstone gas accumulation mechanisms and sweet spot prediction, Triassic Xujiahe Formation, Sichuan Basin, China

The prediction of continental tight sandstone gas sweet spots is an obstacle during tight sandstone gas exploration. In this work, the classic physical fluid charging experimental equipment is improved, the combination of the gas migration and accumulation process with the pore network numerical simulation method is investigated, and application of the permeability/porosity ratio is proposed to predict the gas saturation and sweet spots of continental formations. The results show that (1) as the charging pressure increases, the permeability of the reservoir increases because more narrow pore throats are displaced in the percolation process;and (2) based on pore network numerical simulation and theoretical analysis, the natural gas migration and accumulation mechanisms are revealed. The gas saturation of tight sandstone rock is controlled by the gas charging pressure and dynamic percolation characteristics. (3) The ratio of permeability/porosity and fluid charging pressure is proposed to predict the gas saturation of the formation. The ratio is verified in a pilot and proven to be applicable and practical. This work highlights the tight sandstone gas migration and accumulation mechanisms and narrows the gap among microscale physical experiments, numerical simulation research, and field applications.

Group classification of mixed oils in central Junggar Basin,Northwest China and their migration

The produced oils in central Junggar Basin are commonly mixed in origin.In this paper,in order to reveal this complexity and thereby provide valuable clues to the study of oil source and formation mechanism,genetic groups of the mixed oils were classified and their migration/accumulation was investigated.Based on the artificial oil mixing experiments,some representative biomarkers of the mixed oils showed varying tendencies according to mixing ratios of the oils.Hence,these biomarkers are useful for determining the origin of the mixed oils.According to the criteria,oils in the area were divided into four basic groups,i.e.,the Lower Permian Fengcheng oil,the Middle Permian Lower Wuerhe oil,the Jurassic source derived oil,and the mixed oil(including the Lower and Middle Permian mixed oil and the Permian and Jurassic mixed oil).Oil migration and accumulation were discussed in combination with the geological background.

Hydrocarbon Generation, Migration, and Accumulation in the Eocene Niubao Formation in the Lunpola Basin, Tibet, China: Insights from Basin Modeling and Fluid Inclusion Analysis

The Eocene Niubao Formation is the primary research target of oil exploration in the Lunpola Basin.Crude oil was extracted from Well Z1 on the northern margin of the basin in 1993.In this study,an integrated evaluation of the source rock geothermal,and maturity histories and the fluid inclusion and fluid potential distributions was performed to aid in predicting areas of hydrocarbon accumulation.Due to the abundance of organic matter,the kerogen types,maturity,and oil-sources correlate with the geochemical data.The middle submember of the second member of the Niubao Formation(E2n^2-2)is the most favorable source rock based on the amount of oil produced from the E2n^2-3and E2n^3-1reservoirs.One-and twodimensional basin modeling,using BasinMod software,shows that the E2n^2-2source rock started to generate hydrocarbon at 35-30 Ma,reached a maturity of Ro=0.7%at 25-20 Ma,and at present,it has reached the peak oil generation stage with a thermal maturity of Ro=0.8%to less than Ro=1.0%.By using fluid inclusion petrography,fluorescence spectroscopy,and microthermometry,two major periods of oil charging have been revealed at 26.1-17.5 and 32.4-24.6 Ma.The oil accumulation modeling results,conducted by using the Trinity software,show a good fit of the oil shows in the wells and predict that the structural highs and lithologic transitions within the Jiangriaco and Paco sags are potential oil traps.

Model of Fault Controlling Petroleum Accumulation in Linshang Fault Zone,Huimin Depression

Fault controlling petroleum accumulation is mainly reflected in hydrocarbon migration and sealing in accumulation periods.By fault activity rate analysis and fuzzy comprehensive sealing evaluation in different places of Linshang Fault Zone(LFZ),LFZ controlling petroleum accumulation shows a lot of spatiotemporal differences:(1) main branch of

东濮凹陷北部古近系沙三段超压岩性油气藏成藏机理

东濮凹陷深部储层致密,超压广泛发育,油气生运聚过程复杂。利用测井、录井、钻井及地球化学分析等资料,对东濮凹陷北部古近系沙三段超压的形成机制、超压对源岩与储层的影响以及油气运移动力进行了系统研究,并阐明深层超压岩性油气藏的成藏机理。研究结果表明:(1)东濮凹陷北部古近系沙三段超压岩性油气藏类型主要包括砂岩上倾尖灭油气藏、砂岩透镜体油气藏、裂缝油气藏3种纯岩性油气藏和岩性-构造油气藏、构造-岩性油气藏2种复合油气藏。岩性油气藏主要分布于东濮凹陷北部地区,尤其在前梨园洼陷、海通集洼陷、柳屯洼陷及濮城—卫城洼陷周边,具有“环洼有序分布”的特征。(2)研究区厚层膏盐岩发育及生烃过程产生的深层超压对烃源岩的生烃具有抑制作用,有效扩大了生油窗,增强了深部源岩的生烃能力,促进了其对环洼岩性油气藏的大规模近源供烃;膏盐岩发育、早期快速埋藏、超压的抗压实作用和晚期发育的溶蚀作用控制了优质储层的分布;深部广泛发育的超压和浮力协同作用为深层油气运移提供了有效动力。(3)研究区东部洼陷带为“单洼单源、早混相晚气相、自生自储、超压驱动运聚”成藏模式;东部陡坡带为“单洼多源、早混相晚气相、超压-浮力驱动侧向运聚”成藏模式;西部斜坡带为“单洼多源、油相、超压-浮力驱动侧向运聚”成藏模式;西部洼陷带为“单洼单源、油相、超压-浮力驱动侧向运聚”成藏模式。

塔里木盆地北部富满地区超深层走滑断裂带碳酸盐岩油气差异成藏成因探讨

塔里木盆地北部超深层走滑断裂体系海相碳酸盐岩油气勘探开发近年来取得了重大突破,但富满油田油气分布与富集特征差异显著,走滑断裂控制下的超深层油气差异成藏机理尚不清楚。研究了富满地区走滑断裂几何结构及其演化过程,探讨其在油气运聚成藏中的作用,分析油气成藏富集机理,提出了油气富集主控因素。研究结果表明:(1)研究区走滑断裂经历了早期伸展或弱挤压,中期压扭、伸展或平移走滑,晚期定型、继承发育或张扭反转的动力学演化过程。FI5断裂带和FI17断裂带挤压、剪切和拉张应力交替发育,不同部位演化差异明显,FI7断裂带和FI16断裂带以剪切应力和拉张应力为主,演化过程相对简单。(2)演化过程不同的断裂形成了不同的几何结构,造成通源性、输导性与储集性强弱差异配置不同,从而形成了3种不同的油气充注方式。FI5断裂带和FI16断裂带油气以垂向充注为主,FI7断裂带油气以侧向运移调整为主,FI17断裂带为垂向充注-侧向运移复合型。(3)断裂演化过程差异控制了油气充注过程。东部断裂晚期活动性强,喜马拉雅期高成熟裂解气大量充注成藏,形成了“西油东气”的格局。断裂带内不同部位演化过程差异加剧了断裂内油气性质变化的复杂性。(4)垂向充注型油气藏中通源性、输导性和储集性的耦合配置关系控制了油气富集程度,充注期次差异控制了油气性质变化,油气侧向运移为主的油气藏中储集性及侧向连通程度控制了油气富集程度及油气性质的变化。

库车前陆冲断带构造分层变形特征

库车前陆冲断带地震资料信噪比低,具有多解性。利用高分辨率三维地震、钻井、油气分析化验等资料,对库车前陆冲断带地层组合进行系统描述,精细解释构造模型,深入剖析油气成藏体系,认为库车前陆冲断带发育古近系和新近系膏盐岩层及三叠系和侏罗系煤层2套滑脱层,具有分层滑脱、垂向叠置、多期变形的特征,浅层构造发育盖层滑脱褶皱,深层发育基底卷入式叠瓦状逆冲构造,膏盐岩层和煤层发生滑脱塑性变形,发育加里东运动期、海西运动晚期—印支运动期和燕山运动期—喜马拉雅运动期3期断裂,海西运动晚期—印支运动期构造控制中生界沉积,由北向南具有超覆减薄的特征。库车前陆冲断带分层构造变形控制油气分层运聚,煤层以上的油气主要来自侏罗系烃源岩,煤层之下的油气主要来自三叠系,三叠系烃源岩生烃量占60%,大量油气仍保存在煤层之下。

中国含油气盆地不同构造样式及其油气地质意义

多类型构造样式的控油气作用是油气勘探面临的重要科学问题。基于前人研究认识成果、勘探经验的总结,对中国含油气盆地内不同构造样式的演化及成因模式进行了系统梳理,解析了不同构造样式对油气成藏的控制作用。研究认为:①中国含油气盆地主要发育伸展构造、收缩构造、走滑构造和叠加构造4种构造样式。伸展构造主要控制盆地建造过程,收缩构造、走滑构造主要控制盆地改造过程。②不同构造类型的控油气作用差异明显,伸展构造主要控制盆地烃源岩、有利储集体和盖层等油气聚集成藏要素的发育,收缩构造、走滑构造和叠加构造主要控制油气运移与圈闭条件的演化。③在构造与其他要素复合作用下,断裂自身也可以作为一类储集体,成为油气聚集的空间,这一类断裂油气藏是当前油气勘探的新领域。

断盖配置组合下、中、上部油气运聚空间纵向分布刻画方法及其应用

为了搞清含油气盆地断裂与盖层配置(简称断盖配置)组合下、中、上部油气纵向分布规律,在断盖配置组合封闭特征及其下油气运聚空间纵向分布研究的基础上,通过油源断裂输导油气部位和油源断裂与上中下区域性泥岩盖层配置封闭和不封闭部位叠合,建立了一套断盖配置组合下、中、上部油气运聚空间纵向分布的刻画方法,并利用其刻画了渤海湾盆地歧口凹陷港东断裂与沙河街组一段中亚段(简称沙一中亚段)、东营组二段(简称东二段)和明化镇组区域性泥岩盖层配置组合油气运聚空间纵向分布,结果表明:港东断裂与沙一中亚段、东二段和明化镇组区域性泥岩盖层配置组合沙一下亚段油气运聚空间纵向分布主要在其东部和西部,港东断裂与沙一中亚段、东二段和明化镇组区域性泥岩盖层配置组合东三段和馆陶组油气运聚空间纵向分布主要在其中部。港东断裂与沙一中亚段、东二段和明化镇组配置组合沙一下亚段油气运聚空间纵向分布相对发育,有利于油气运聚成藏,港东断裂与沙一中亚段、东二段和明化镇组配置组合东三段和馆陶组油气运聚空间纵向分布相对不发育,不利于油气运聚成藏,与目前港东断裂处沙一下亚段、东三段和馆陶组内已发现油气分布相吻合,表明该方法用于刻画断盖配置组合下、中、上部油气运聚空间纵向分布是可行的。

杭锦旗地区二叠系储层油气成藏期次及流体势特征

杭锦旗地区是鄂尔多斯盆地北部重要的含油气区,油气成藏期次及流体势研究有利于探究油气充注的世代以及流体势的分布特征,并进一步判定成藏期油气的运移方向。本文以什股壕区块和十里加汗区块5口井的二叠系下石盒子组盒一段储层砂岩为研究对象,基于流体包裹体分析厘定油气成藏期次,并结合流体势理论计算研究区关键成藏期的流体势并揭示油气的运移方向。研究结果显示:什股壕区块盒一段储层油气的成藏时间为132~102 Ma;十里加汗区块盒一段储层油气的成藏时间为132~101 Ma。杭锦旗北部的什股壕盒一段储层油气的流体势为18 128~22 872 J/kg;杭锦旗南部的十里加汗区块盒一段储层油气的流体势为22 975~27 153 J/kg。本文认为研究区二叠系盒一段储层油气成藏时间在早白垩世,十里加汗区块整体的流体势要高于什股壕区块,油气具备由南部向北部运移的趋势。

渤海湾盆地石臼坨凸起秦皇岛27-3大型油田发现与地质新认识

渤海湾盆地石臼坨凸起历经50余年勘探,在凸起高部位背斜区发现了3个浅层亿吨级大油田,而低部位斜坡区浅层由于构造圈闭不发育,勘探程度较低,近10年无规模性发现。随着渤海海域勘探程度提高,现已全面进入岩性勘探阶段,针对石臼坨凸起东段顺向断裂斜坡区浅层油气运移、岩性圈闭刻画和油气成藏规律等展开了深入系统研究。研究认为:(1)研究区南北两侧被富生烃凹陷夹持,凸起边界大断层晚期强烈活动和陡坡带近源扇体普遍发育使凸起区成为规模性油气运聚的最终指向区;(2)凸起边界大断层在馆陶组开启系数最小,馆陶组含砾砂岩输导层是石臼坨凸起之上主要的油气横向运移通道;(3)馆陶组输导脊坡度和切脊断层组合控制顺向斜坡区油气的垂向输导,当坡度小于1°且断层长度大于2.50 km、成藏期断距大于40 m时斜坡区可产生规模性的油气垂向运移,突破顺向断裂斜坡区“过路不留”的传统认识;(4)在凸起斜坡区,与构造脊方向斜交的砂体有利于油气保存,同时,提出井约束谱蓝化整形高分辨率处理技术,实现了对斜坡区岩性圈闭有效刻画,优选出保存条件较好的斜向砂体开展钻探部署。基于上述新认识、新技术,2023年在石臼坨凸起东段顺向斜坡区成功评价了秦皇岛27-3亿吨级油田,实现了勘探老区浅层挖潜的重大突破,为渤海湾盆地高成熟探区持续油气发现提供了借鉴。

渤东凹陷新生代伸展-走滑叠合断裂时空差异演化模式及控藏效应

以三维地震精细解释为基础,通过构造剖面恢复,系统分析了渤东凹陷新生代伸展-走滑叠合断裂的时空差异演化特征及控藏作用。研究结果表明:(1)渤东凹陷新生代广泛发育以NNE向为主干、NE向为派生、NW向为叠加的伸展-走滑叠合断裂体系,可划分为强伸展-弱走滑断裂和强走滑-弱伸展断裂2类;整体具有深浅分层、南北分段的特征,纵向上,古近系主要发育强伸展-弱走滑断裂,断裂大而稀,新近系—第四系主要发育强走滑-弱伸展断裂,断裂小而密;平面上,同一断裂在不同段的构造组合样式存在差异。(2)研究区新生代伸展-走滑叠合断裂的演化主要表现为北部断裂活动强度“早强晚弱”,中部断裂继承性持续发育,南部断裂活动强度“早弱晚强”;演化模式分为初始断陷(孔店组—沙四段沉积期)、强烈断陷(沙三段—东营组沉积期)和走滑坳陷(馆陶组—平原组沉积期)3个阶段,初始断陷阶段,NNE—NE向强伸展与弱走滑叠合,NE向强伸展-弱走滑断裂为主控,NW向先存断裂活化,分割凹陷;强烈断陷阶段,NNE—NE向强伸展与弱走滑叠合,NNE向强伸展-弱走滑断裂变为主控,NW向断裂活动减弱或停止;走滑坳陷阶段,NNE向强走滑与弱伸展叠合,断裂不控制沉积,但对地层展布具有调整作用。(3)研究区伸展-走滑叠合断裂的发育演化与油气成藏密切相关,整体具有“早期伸展控源、晚期走滑控运、多期叠加控圈”的特征,东部斜坡带是油气运聚的有利区。