Coupled stratigraphic and fault seal modelling used to describe trap integrity in the frontier Bight Basin,Australia

Top seals and faults represent key risks to trap integrity and therefore preservation of hydrocarbons in the frontier Ceduna Sub-basin, offshore Southern Australia. Due to a paucity of well data in the basin, to provide constraint to the stratigraphic distribution of the prospective Cretaceous deltaic and marine sequences, stratigraphic forward modelling was utilised to create facies, grain size and V_shale volumes. These modelled V_shale volumes were subsequently used to investigate the structural control(s) on potential hydrocarbon leakage and migration within key stratigraphic sequences in the sub-basin.A set of coarse (20 km horizontal resolution), large scale (1100 × 600 km) stratigraphic forward models simulated the deposition of Late Jurassic to Tertiary stratigraphic sequences in the sub-basin with an initial 1 Ma interval. Smaller (80 × 60 km), finer scale (0.5 km horizontal resolution, 200 ka interval), models focussing on the Tiger and Hammerhead Supersequences over the Trim 3D seismic survey were used to investigate fault seal and top seal frameworks, using shale gouge ratio and silt and shale thicknesses from V_shale volume. Four stratigraphic forward models were produced to match a range of estimates of V_shale derived from the Gnarlyknots-1A well, the only well penetrating the central Ceduna Sub-basin. These stratigraphies were in turn integrated into a geological model interpreted from the Trim 3D seismic survey creating a geocellular model to test potential migration and trapping scenarios for potential hydrocarbons generated in the sub-basin.Fault and top seal models from the most likely scenario suggest (i) restricted potential for structural trapping near the base of the Tiger Supersequence, (ii) the possible presence of a regional migration pathway associated with sandy shoreface deposits at the transition between the Tiger and Hammerhead Supersequences, and (iii) the association of intraformational top seals and increasing fault seal potential in the deltaic sediments of the Hammerhead Supersequence feasibly resulting in a series of stacked structural traps.     

松南气田登娄库—泉头组天然气成藏特征分析

松南气田位于松辽盆地南部长岭断陷中央隆起带达尔罕断凸带腰英台深层构造高部位.通过分析解剖烃源岩、输导等,认为松南气田登娄库—泉头组天然气藏具有双向供烃的特征;达尔罕断裂是控制气藏规模的主断裂,它的开启与封闭直接决定天然气藏的形成保存及破坏散失.在典型气藏解剖的基础上,综合油气成藏条件,总结了成藏规律：多期生烃,北、西次凹供烃、近距离运移,长期运移指向、聚集,深层储盖组合匹配.     

海上复杂断块油田储层流动单元研究与应用——以北部湾A油田A1/A5断块为例

开展海上复杂断块油田储层流动单元研究对刻画储层连通程度、剩余油的分布情况有着十分重要的实际意义。以北部湾A油田A1/A5断块为例,首先对复合砂体内单砂体的识别来建立流动单元研究的精细地质格架,然后结合断层封闭性、隔夹层分布、砂体接触关系所形成的渗流屏障进行流动单元划分。利用主成分分析和相关性分析的方法进行参数优选,确定孔隙度、泥质含量、渗流系数作为研究区流动单元分类的主要参数,并通过神经网络聚类分析将流动单元分为3类。在单井、剖面、平面流动单元展布研究的基础上,运用截断高斯模拟方法建立流动单元三维地质模型。结果表明:Ⅰ类流动单元具有最好的储渗能力,所钻油井累计产量比较高,但分布范围局限,成土豆状分布于水下分流河道中心部分;Ⅱ类分布范围最广,储渗能力较好,分布在水下分流河道微相中,剩余油分布较多,通过调整挖潜可以开发其生产潜力;Ⅲ类大多成条带状分布,主要位于水下溢岸砂沉积部位,储渗能力最差,产量很低,其开发潜力也比较差。     

Properties and shale oil potential of saline lacustrine shales in the Qianjiang Depression,Jianghan Basin,China

The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (R_o ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S₁ × 100/TOC, mg HC/g TOC and S₁, mg HC/g rock) and brittleness data demonstrate that the Eq3^3x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation.     

张扭性断裂带的生长过程与油气穿断运移评价--以珠江口盆地恩平凹陷为例

张扭性断裂带是珠江口盆地普遍发育的断裂类型,是沟通深部烃源岩与中浅部储层的关键,是油气运移、聚集分析的核心环节。以恩平凹陷E18雁列式断裂带为例,基于三维地震、测井和钻井地质数据,采用T-x图、T-z图及活动速率图方法,恢复E18断裂带的生长过程及分段特征,并依据岩性对接、泥岩涂抹、断层岩发育特征,评价油气穿断裂侧向运移的条件。结果表明,E18断裂带在裂陷期是单一断裂,裂后期表现为雁列形态,活动过程包含4个阶段,活动中心由西部转移至中部,大规模生排烃时期最大活动速率可达20m/Ma,形成2个良好的垂向疏导中心,分段特征明显;油气容易穿透E18断裂带珠海组和韩江组下段2套地层发生侧向运移,并且连接部位是最有利于油气穿断运移的部位。E18断裂带生长过程和油气穿断侧向运移的评价有助于认识E18a油田和E18f油田的成藏过程。     

Migration of methane at the diapiric structure of the western continental margin of India — insights from seismic data

Investigations are being carried out to locate the indirect evidences of gas occurrences in the Indian Continental Margins by identifying features like pockmarks, shale diapirs, venting as well as bottom simulating reflectors (BSR). We investigate one such case of a shale diapirs. Occurrence of free gas and gas hydrates is reported using a complex trace analysis to study the variation of reflection strength and instantaneous frequency along individual reflections. A frequency analysis over the flank of the shale diapir indicates attenuation of high frequencies, possibly representing the migration of fluids (probably methane) along the fault pathways. Similarly a plot of reflection strength along an individual reflector shows the migration pathways and significant blanking.     

Calibrating fault seal using a hydrocarbon migration model of the Oseberg Syd area,Viking Graben

It is widely acknowledged that fault rock capillary properties are important in controlling the distribution of hydrocarbons in sedimentary basins, and methods exist for predicting the capillary seal capacity of prospect bounding faults. However, fault seal capacity is rarely incorporated into models of hydrocarbon migration. This paper presents the results of migration modelling of the Oseberg Syd area of the Viking Graben incorporating fault rock capillary properties. Seal capacity is calculated in the model as a function of Shale Gouge Ratio (SGR), i.e. the percentage shale in the sequence moved past a point on a fault. Over 3000 model realisations were run for different SGR to fault seal capacity relationships and the calculated hydrocarbon distributions were compared with known distributions. Realisations were ranked according to the closeness of fit between model and actual oil–water contacts for 7 traps. The best-fit to all 7 traps was provided by realisations with significant seal capacity at SGR values greater than ca. 0.2; a value which is in agreement with an independently derived fault-by-fault calibration between SGR and seal capacity. The level of fill calculated for an individual trap is extremely sensitive to minor changes in the seal capacity relationship because it is controlled not only by the seal capacities of the faults that bound the trap, but also by the pattern of fill–spill of upstream traps. This sensitivity to minor changes in seal capacity introduces large uncertainties when fault seal capacity relationships are used in a predictive mode and emphasises the requirement for migration modelling in fault seal prospect evaluation.     

Oil migration through preferential petroleum migration pathway (PPMP) and polycyclic faults: A case study from the Shijiutuo Uplift,Bohai Bay basin,China

The Shijiutuo uplift is an oil enriched uplift in the offshore Bohai Bay Basin. Petroleum migration is a key factor for oil enrichment in Neogene reservoirs far away from the hydrocarbon kitchen. In this article, an integration of geological, geophysical and geochemical analyses are employed to investigate the petroleum migration and accumulation on the Shijiutuo uplift. Hydrocarbons in the QHD32-6 and QHD33 oilfields are mainly originated from the third (E₂s₃) and first (E₂s₁) member of the Shahejie Formation. The shallow traps have significant contributions of late-stage E₂s₁-derived oil. Lateral petroleum migration is a major mechanism forming large oilfields on the Shijiutuo uplift. The large oilfields have multiple hydrocarbon kitchens, multiple source rocks, and numerous preferential petroleum migration pathways (PPMPs). Once petroleum arrives at the structural highs on the Shijiutuo uplift through the Guantao Formation (N₁g) carrier-beds, neotectonic faults cutting through Guantao (N₁g) and Minghuazhen (N₁m^L) formations could serve as effective conduits for vertical petroleum migration. Neotectonic faults have experienced polycyclic fault activities. Fluid inclusions indicate episodic hydrocarbon charging. Crude oils display duplex properties of biodegradation and non-biodegradation, which is strong evidence for multiple and episodic oil charging on the Shijiutuo uplift. Finally, episodic petroleum charging along polycyclic neotectonic faults causes the late-stage E₂s₁-derived oils to occur in the shallow reservoirs.     

Quantitative characterization of connectivity and conductivity of sandstone carriers during secondary petroleum migration,applied to the Third Member of Eocene Shahejie Formation,Dongying Depression,Eastern China

Studies on migration pathways remain qualitative, albeit extensive quantification of migration forcing. In this study, hydrocarbon carriers are defined as carrier units and their corresponding carrier beds for the Third Member of Eocene Shahejie Formation in the Dongying Depression, Bohai Bay Basin, eastern China, on the basis of their lithofacies and physical properties, spatial relationships, and data availability; secondary migration conduits are then quantified. A carrier unit is defined as a stratigraphic unit that contains microscopically porous and permeable carrier beds and is covered by regional seals. The carrier beds are macroscopically and physically connected to each other within a carrier unit and are hydrodynamically connected during secondary migration. A method of quantifying sandstone carrier units using common physical properties is developed. First, a carrier unit containing potential carrier beds is identified on the basis of lithofacies and their lateral changes. Second, physical connectivity of sandstone carrier beds is assessed on the basis of percolation theory. Third, the hydrodynamic connectivity of a sandstone carrier unit is analyzed using effective parameters that may reflect the hydraulic circulation in the carrier unit. Last, the conductivity of a sandstone carrier bed is quantitatively characterized using appropriate physical property parameters. The results for sandstone carrier units in the Third Member of the Shahejie Formation are used in numerical models addressing Pleistocene secondary migration. The model results explain the discovered accumulation and hydrocarbon shows well; and the model predictions on exploration targets have been confirmed by drilling.     

Structural regime and its impact on the mechanism and migration pathways of hydrocarbon seepage in the southern Gulf of Suez rift: An approach for finding new unexplored fault blocks

A Natural active oil seepage occurs at the intersection of the NW-oriented rift coastal fault and a NE-oriented cross fault which bound the southwest dipping Little Zeit tilted fault block at the southwestern side of the Gulf of Suez, Egypt. Detailed surface geological mapping followed by subsurface mapping using aeromagnetic, seismic and borehole data of Ras El Ush oilfield (the nearest oil field to the seepage) provide a reliable hydrocarbon migration pathway model of the area.The proposed model suggests that hydrocarbons migrated upward at the intersection of a NE-oriented and the NW-oriented rift coastal faults where they found their way to the surface. The Nubia Sandstone occurs south of Ras El Ush oilfield in a trap door structure and probably entrapped some of the migrating hydrocarbons while a probable oil-water-contact at −1000 m which resulted into the migration of hydrocarbon through the damage zone of the northeast fault.The original oil in place of the predicted reservoir is estimated to be more than 47.5 MMBO which encourages the design makers for more investigation of this reservoir to increase its certainty and putting it in the plan of the future investments.     

Defining the 3D geometry of thin shale units in the Sleipner reservoir using seismic attributes

Defining the 3D geometry and internal architecture of reservoirs is important for prediction of hydrocarbon volumes, petroleum production and storage potential. Many reservoirs contain thin shale layers that are below seismic resolution, which act as impermeable and semi-permeable layers within a reservoir. Predicting the storage volume of a reservoir with thin shale layers from conventional seismic data is an issue due to limited seismic resolution. Further, gas chimneys indicative of gas migration pathways through thin shale layers, are not easily defined by conventional seismic data. Additional information, such as borehole data, can be used to aid mapping of shale layers, but making lateral predictions from 1D borehole data has high uncertainty. This paper presents an integrated workflow for quantitative seismic interpretation of thin shale layers and gas chimneys in the Utsira Formation of the Sleipner reservoir. The workflow combines the use of attribute and spectral analysis to add resolution to conventional seismic amplitude data. Detailed interpretation of these analyses reveals the reservoirs internal thin shale architecture, and the presence of gas chimneys. The comprehensive interpretation of the reservoirs internal structure is used to calculate a new reservoir storage volume. This is done based on the distribution of sand and interpreted shale layers within the study area, for this active CO₂ storage site.     

Numerical study of multi-period palaeotectonic stress fields in Lower Cambrian shale reservoirs and the prediction of fractures distribution: A case study of the Niutitang Formation in Feng'gang No. 3 block,South China

Fractures not only control the distribution of oil and gas reservoirs, but also are key points in the research of oil and gas reservoir development programmes. The tectonic fractures in the Lower Cambrian shale reservoirs in the Feng'gang No. 3 block are effective reservoir spaces for hydrocarbon accumulation, and these fractures are controlled by palaeotectonic stress fields. Therefore, quantitatively predicting the development and distribution of tectonic fractures in the Lower Cambrian shale reservoir is important for the exploration and exploitation of shale gas in the Feng'gang No. 3 block. In the present study, a reasonable geological, mechanical and mathematical model of the study area was established based on the faults systems interpreted from seismic data, fracture characteristics from drilling data, uniaxial and triaxial compression tests and experiments on the acoustic emissions (AE) of rocks. Then, a three-dimensional (3-D) finite element method is applied to simulate the palaeotectonic stress field with the superposition of the Yanshan and Himalayan movements and used to predict the fracture distribution. The simulation results indicate that the maximum principal stress value within the study area ranged from 269.97 MPa to 281.18 MPa, the minimum principal stress ranged from 58.29 MPa to 79.64 MPa, and the shear stress value ranged from 91.05 MPa to 106.21 MPa. The palaeotectonic stress field is controlled by the fault zone locations. The fracture development zones are mainly controlled by the tectonic stress fields and are located around the faults, at the end of the fault zones, at the inflection point and at the intersection of the fault zones.     

Oil-oil and oil-source rock correlations in the Alpine Foreland Basin of Austria: Insights from biomarker and stable carbon isotope studies

The Alpine Foreland Basin is a minor oil and moderate gas province in central Europe. In the Austrian part of the Alpine Foreland Basin, oil and minor thermal gas are thought to be predominantly sourced from Lower Oligocene horizons (Schöneck and Eggerding formations). The source rocks are immature where the oil fields are located and enter the oil window at ca. 4 km depth beneath the Alpine nappes indicating long-distance lateral migration. Most important reservoirs are Upper Cretaceous and Eocene basal sandstones.Stable carbon isotope and biomarker ratios of oils from different reservoirs indicate compositional trends in W-E direction which reflect differences in source, depositional environment (facies), and maturity of potential source rocks. Thermal maturity parameters from oils of different fields are only in the western part consistent with northward displacement of immature oils by subsequently generated oils. In the eastern part of the basin different migration pathways must be assumed. The trend in S/(S + R) isomerisation of ααα-C₂₉ steranes versus the αββ (20R)/ααα (20R) C₂₉ steranes ratio from oil samples can be explained by differences in thermal maturation without involving long-distance migration. The results argue for hydrocarbon migration through highly permeable carrier beds or open faults rather than relatively short migration distances from the source. The lateral distance of oil fields to the position of mature source rocks beneath the Alpine nappes in the south suggests minimum migration distances between less than 20 km and more than 50 km.Biomarker compositions of the oils suggest Oligocene shaly to marly successions (i.e. Schoeneck, Dynow, and Eggerding formations) as potential source rocks, taking into account their immature character. Best matches are obtained between the oils and units a/b (marly shale) and c (black shale) of the “normal” Schöneck Formation, as well as with the so-called “Oberhofen Facies”. Results from open system pyrolysis-gas chromatography of potential source rocks indicate slightly higher sulphur content of the resulting pyrolysate from unit b. The enhanced dibenzothiophene/phenanthrene ratios of oils from the western part of the basin would be consistent with a higher contribution of unit b to hydrocarbon expulsion in this area. Differences in the relative contribution of sedimentary units to oil generation are inherited from thickness variations of respective units in the overthrusted sediments. The observed trend towards lighter δ¹³C values of hydrocarbon fractions from oil fields in a W-E direction are consistent with lower δ¹³C values of organic matter in unit c.     

Hydrocarbon accumulation model for Neogene traps in the Chengdao area,Bohai Bay Basin,China

Chengdao is an offshore area in the Bohai Bay Basin that contains approximately 25.7 × 10⁸ bbl of oil and gas reserves within the sandstone reservoirs in Neogene strata. However, previous predictions of hydrocarbon accumulation in Neogene traps are inaccurate, resulting in a current failure rate of 50% when drilling for hydrocarbons in this area. To build an improved exploration model for Neogene traps, we select 92 traps from Neogene strata in the Chengdao area to quantify the filling degree, which is an indicator of hydrocarbon accumulation efficiency. The quantified filling degree is based on actual geological and exploration data and differs significantly among various trap types. The filling degree of traps also varies significantly with their structural locations and decreases generally from the northwest to the southeast along the Chengbei Fault zone. Vertically, the filling degree is highly heterogeneous, initially increasing from the bottom to the middle of Neogene strata and then decreasing towards the top of the strata. These Neogene hydrocarbon reservoirs are sourced from the Paleogene, and as they lay vertically away from the source rocks, their hydrocarbon enrichment is constrained largely by hydrocarbon migration distance and vertical migration pathways. The sealing capacity of faults and cap rocks, sandbody orientation and reservoir sedimentary facies determine the maximum column height, which in turn affects the amount of hydrocarbon accumulation within these traps. A scatter plot analysis of individual controls and volumetric filling for each trap type is compiled using multivariate linear regression analysis to quantify controls and the dominant control of hydrocarbon accumulation is determined.     

Comprehensive polynomial simulation and prediction for Langmuir volume and Langmuir pressure of shale gas adsorption using multiple factors

In this study, 32 experimental measurements on the isothermal adsorption of methane for 18 shale samples from China's three largest continental oil basins—Songliao, Bohai Bay, and Ordos basins—were used to construct comprehensive polynomial simulation and prediction models for Langmuir volume and Langmuir pressure. The models were based on shale properties (total organic carbon (TOC) content, amount of residual hydrocarbon S₁, and mineral composition of rocks) and adsorption condition (temperature) using a weighted sum of multiple variables. The influences of various factors were quantitatively characterized, and the prediction accuracy was verified. Langmuir volume is mainly affected by temperature, shale TOC content, amount of residual hydrocarbon, and clay mineral content; Langmuir pressure is mainly affected by clay, carbonate, feldspar and illite content (because shale pore size can be affected by shale mineral composition). Based on the resource potential and the producibility of shale gas, the area suitable for shale gas exploration and development should have high abundance of organic matter (TOC and residual hydrocarbon S₁), low clay mineral content and feldspar content, high conversion rate of montmorillonite to illite (strong diagenesis), and high carbonate content. The comprehensive polynomial prediction model can effectively simulate and predict Langmuir volume and Langmuir pressure, thereby reducing the amount of work necessary for evaluation of shale gas resource potential and economic feasibility.     

长岭坳陷腰英台油田青山口组油气成藏主控因素分析

腰英台油田区是松辽盆地南部近几年发现的具有超亿吨级储量规模的大型含油气区。结合勘探实践对腰英台地区青山口组油气成藏条件分析表明,油气成藏的主控因素包括烃源、储层和输导三个方面。油气成藏主要围绕乾安次凹生烃中心,烃源岩控制油藏的聚集与分布;断裂一方面作为输导体系,另一方面控制着不同类型油藏的平面分布;沉积微相控制砂体的平面分布以及砂体的储集物性。最终指出了近源带、断裂带、砂体发育带三者叠置区是下步勘探的有利方向。     

东海陆架盆地海礁凸起的油气潜力分析

根据对海礁凸起地区的地质、地球物理和地球化学资料的分析，将海礁凸起划分为性质截然不同的南、北两个部分，推测南部海礁凸起尤其是东南翼具有较好的油气潜力。因为南部海礁凸起紧邻主要生油凹陷（即西湖凹陷）；储集性能较好的渐新统花港组可能在凸起的东南翼分布较厚；NWW向的深部断裂为南部海礁凸地区的断块圈闭、潜山和披覆构造的形成提供了条件，同时也起着油气运移通道的作用。从地化异常指标来看，该区油气运移的方向也是从SE向到NW向。因此，加大对南部海礁凸起的勘探力度，并重视南部凸起区可能具有的油气潜力，将有可能发现类似于流花11－1、崖城13－1和绥中36－1的大型油气田。     

Evaluation of Eocene source rock for potential shale oil and gas generation in north Cambay Basin,India

Source rock potential of 108 representative samples from 3 m intervals over a 324 m thick shale section of middle Eocene age from the north Cambay Basin, India have been studied. Variation in total organic carbon (TOC) and its relationship with loss on ignition (LOI) have been used for initial screening. Screened samples were subjected to Rock-Eval pyrolysis and organic petrography. A TOC log indicated wide variation with streaks of elevated TOC. A 30 m thick organic-rich interval starting at 1954 m depth, displayed properties consistent with a possible shale oil or gas reservoir. TOC (wt%) values of the selected samples were found to vary from 0.68% to 3.62%, with an average value of 2.2. The modified van Krevelen diagram as well as HI vs. T_max plot indicate prevalence of Type II to Type III kerogen. T_max measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%R_o of 0.63, 0.65 and 0.67 at 1988 m, 1954 m, and 1963 m, respectively). Quantification of hydrocarbon generation, migration and retention characteristics of the 30 m source rock interval suggests 85% expulsion of hydrocarbon. Oil in place (OIP) resource of the 30 m source rock was estimated to be 3.23 MMbbls per 640 acres. The Oil saturation index (OSI) crossover log showed, from a geochemical perspective, moderate risk for producing the estimated reserve along with well location for tapping the identified resource.     

AMG preconditioning for sedimentary basin simulations in Temis calculator

Basin modelling aims at reconstructing the time evolution of a sedimentary basin in order to make quantitative predictions of geological phenomena leading to hydrocarbon accumulations. It accounts for porous medium compaction, heat transfer, hydrocarbon generation and migration. These physical phenomena are modelled by partial differential equations [Schneider, F., Wolf, S., Faille, I., Pot, D. 2000. A 3D basin model for hydrocarbon potential evaluation: application to Congo offshore. Oil and Gas Science Technologie, Rev-IFP 55, 3–13] representing the mass balances of solid, fluids (water and oil) coupled with Darcy's law and a compaction law. These equations are discretized using a cell-centered Finite Volume method in space and an implicit Euler integration in time. At each time step, the resulting nonlinear system is solved using Newton's method ending up at each Newton iteration with the solution of a linear system which represents the most cpu-time-consuming part of the basin simulator.     

下刚果—刚果扇盆地断裂特征及其对油气成藏的影响

下刚果—刚果扇盆地油气资源丰富、油气成藏条件优越。但由于受到盐岩的活动及区域构造应力场的作用,形成了复杂的断裂系统。此文系统分析了下刚果—刚果扇盆地的断裂特征及其对油气成藏的影响,研究认为该区平面上主要发育5个断裂带,纵向上主要发育上下两套断裂系统。断裂的形成和演化可分为三个期次,相对应可将断层分为三个级别的断层。断层的形成机制主要有盐活动及盐构造、重力滑脱作用以及古地貌格局。烃源岩的排烃时间与第三期断层活动时间相匹配,非常有利于油气沿断层进行垂向和斜侧向运移。分析认为研究区主要发育沿断阶带—碳酸盐岩运聚成藏模式、沿断层垂向运聚成藏模式以及沿盐下砂体—盐窗和Focus点运聚成藏模式共三种成藏模式。断层封堵较好,油源断层高度决定了油气运移高度和油气田规模,直接控制着油气的分布层系及规模。研究成果可指导研究区或类似地区的油气勘探。