辽东湾地区锦州25—1油田油气成藏特点和运聚模拟研究

在对构造演化、成藏要素、油源对比、成藏期次分析的基础上,结合Trinity油气运移成藏模拟分析软件对锦州25—1油田的油气运聚模拟研究,分析了形成锦州25—1油田的成藏主控因素,建立了其成藏模式,指出了该地区有利勘探方向。模拟分析结果表明,锦州25—1构造是辽西凹陷沙三段烃源岩生成油气运聚的有利指向区,而优良成藏要素的优势时空配置则是形成锦州25—1油田的关键因素。其成藏模式为：辽西凹陷沙三段烃源岩在东下段时期进入了大量生排烃期,生成的油气为一期充注,充注时间发生在东营组末期,沿东下段时期强烈构造运动伴生的断裂系统、沙二段广泛发育的砂体、沙二段与沙三段之间大型不整合面以及古构造脊所构成的疏导体系运移至沙二段圈闭成藏,而沙三段砂体则可以近源优势成藏。辽西凹陷西斜坡、凹中隆以及古构造脊是今后较为有利的勘探区域。     

Geologic control of natural marine hydrocarbon seep emissions, Coal Oil Point seep field, California

High-resolution sonar surveys, and a detailed subsurface model constructed from 3D seismic and well data allowed investigation of the relationship between the subsurface geology and gas-phase (methane) seepage for the Coal Oil Point (COP) seep field, one of the world’s largest and best-studied marine oil and gas seep fields, located over a producing hydrocarbon reservoir near Santa Barbara, California. In general, the relationship between terrestrial gas seepage, migration pathways, and hydrocarbon reservoirs has been difficult to assess, in part because the detection and mapping of gas seepage is problematic. For marine seepage, sonar surveys are an effective tool for mapping seep gas bubbles, and thus spatial distributions. Seepage in the COP seep field occurs in an east–west-trending zone about 3–4 km offshore, and in another zone about 1–2 km from shore. The farthest offshore seeps are mostly located near the crest of a major fold, and also along the trend of major faults. Significantly, because faults observed to cut the fold do not account for all the observed seepage, seepage must occur through fracture and joint systems that are difficult to detect, including intersecting faults and fault damage zones. Inshore seeps are concentrated within the hanging wall of a major reverse fault. The subsurface model lacks the resolution to identify specific structural sources in that area. Although to first order the spatial distribution of seeps generally is related to the major structures, other factors must also control their distribution. The region is known to be critically stressed, which would enhance hydraulic conductivity of favorably oriented faults, joints, and bedding planes. We propose that this process explains much of the remaining spatial distribution.     

陡坡带油气藏构造特征与油气聚集规律——以渤海油田旅大6构造为例

旅大6构造是渤海海域新近发现的一个中型油田.该构造位于辽东低凸起中南段陡坡带,为层状构造油气藏,垂向上多层系含油,形成典型的“阶梯式”陡坡带复式油气藏.走滑作用对构造形成、储层发育、断层封堵、油气运移都有重要的作用.构造转折端对沉积卸载形成优质储层具有重要作用,奠定了旅大6构造是辽东低凸起中南段有利成藏区的物质基础;辽中一号断层与区域走滑断层同向,具有走滑压扭性质是控圈断层侧封的关键.南北区块以及东二下段、东三段油气丰度迥异,伸展断层的运移能力和控圈断层的封堵能力共同决定了旅大6构造南区东二下段油气的差异富集成藏.     

Improved understanding of petroleum migration history in the Hongche fault zone,northwestern Junggar Basin (northwest China): Constrained by vein-calcite fluid inclusions and trace elements

Calcite veins and cements occur widely in Carboniferous and Permian reservoirs of the Hongche fault zone, northwestern Junggar Basin in northwest China. The calcites were investigated by fluid inclusion and trace-element analyses, providing an improved understanding of the petroleum migration history. It is indicated that the Hongche fault behaved as a migration pathway before the Early Cretaceous, allowing two oil charges to migrate into the hanging-wall, fault-core and footwall reservoirs across the fault. Since the Late Cretaceous, the Hongche fault has been sealed. As a consequence, meteoric water flowed down only into the hanging-wall and fault-core reservoirs. The meteoric-water incursion is likely an important cause for degradation of reservoir oils. In contrast, the footwall reservoirs received gas charge (the third hydrocarbon event) following the Late Cretaceous. This helps explain the distribution of petroleum across the fault. This study provides an example of how a fault may evolve as pathway and seal over time, and how reservoir diagenetic minerals can provide clues to complex petroleum migration histories.     

Utility of GOI,QGF, and QGF-E for interpreting reservoir geohistory and oil remigration in the Hudson oilfield,Tarim basin,northwest China

The physical mechanisms responsible for hydrocarbon migration in carrier beds are well understood. However, secondary migration is one of poorly understood facets in petroleum system. The Carboniferous Donghe sandstone reservoir in the Tarim Basin's Hudson oilfield is an example of a secondary (or unsteady) reservoir; that is, oil in this reservoir is in the process of remigration, making it a suitable geologic system for studying hydrocarbon remigration in carrier beds. Experimental methods including grains containing oil inclusions (GOI), quantitative grain fluorescence (QGF) and quantitative grain fluorescence on extract (QGF-E) -- together with the results from drilling, logging and testing data -- were used to characterize the nature of oil remigration in the Donghe sandstone. The results show that (1) significant differences exist between paleo- and current-oil reservoirs in the Donghe sandstone, which implies that oil has remigrated a significant distance following primary accumulation; (2) due to tectonic inversion, oil remigration is slowly driven by buoyancy force, but the oil has not entered into the trap entirely because of the weak driving force. Oil scarcely enters into the interlayers, where the resistance is relatively large; (3) the oil-remigration pathway, located in the upper part of the Donghe sandstone, is planar in nature and oil moving along this pathway is primarily distributed in those areas of the sandstone having suitable properties. Residual oil is also present in the paleo-oil reservoirs, which results in their abnormal QGF-E. A better understanding of the characteristics of oil remigration in the Donghe sandstone in the Hudson oilfield can contribute to more effective oil exploration and development in the study area.     

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。     

Diagenesis of the palaeo-oil-water transition zone in a Lower Pennsylvanian carbonate reservoir: Constraints from cathodoluminescence microscopy,microthermometry, and isotope geochemistry

Oil-water transition zones in carbonate reservoirs represent important but rarely studied diagenetic environments that are now increasingly re-evaluated because of their potentially large effects on reservoir economics. Here, data from cathodoluminescence and fluorescence microscopy, isotope geochemistry, microthermometry, and X-ray tomography are combined to decipher the diagenetic history of a 5-m-long core interval comprising the oil-water transition zone in a Lower Pennsylvanian carbonate reservoir. The aim is to document the cementation dynamics prior, during, and after oil emplacement in its context of changing fluid parameters. Intergrain porosity mean values of 7% are present in the upper two sub-zones of the oil-water transitions zone but values sharply increase to a mean of 14% in the lower sub-zone grading into the water-saturated portions of the reservoir and a very similar pattern is observed for permeability values. In the top of the water-filled zone, cavernous porosity with mean values of about 24% is found. Carbonate cements formed from the earliest marine to the late burial stage. Five calcite (Ca-1 through 5) and one dolomite (Dol) phase are recognized with phase Ca-4b recording the onset of hydrocarbon migration. Carbon and oxygen cross-plots clearly delineate different paragenetic phases with Ca-4 representing the most depleted δ¹³C ratios with mean values of about −21‰. During the main phase of oil emplacement, arguably triggered by far-field Alpine tectonics, carbonate cementation was slowed down and eventually ceased in the presence of hydrocarbons and corrosive fluids with temperatures of 110–140 °C and a micro-hiatal surface formed in the paragenetic sequence. These observations support the “oil-inhibits-diagenesis” model. The presence an earlier corrosion surface between phase Ca-3 and 4 is best assigned to initial pulses of ascending corrosive fluids in advance of hydrocarbons. The short-lived nature of the oil migration event found here is rather uncommon when compared to other carbonate reservoirs. The study is relevant as it clearly documents the strengths of a combined petrographic and geochemical study in order to document the timing of oil migration in carbonate reservoirs and its related cementation dynamics.     

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.     

Hydrocarbon systems of Northeastern Venezuela: plate through molecular scale-analysis of the genesis and evolution of the Eastern Venezuela Basin

The prolific, oil-bearing basins of eastern Venezuela developed through an unusual confluence of Atlantic, Caribbean and Pacific plate tectonic events. Mesozoic rifting and passive margin development created ideal conditions for the deposition of world-class hydrocarbon source rocks. In the Cenozoic, transpressive, west-to-east movement of the Caribbean plate along the northern margin of Venezuela led to the maturation of those source rocks in several extended pulses, directly attributable to regional tectonic events. The combination of these elements with well-developed structural and stratigraphic fairways resulted in remarkably efficient migration of large volumes of oil and gas, which accumulated along the flanks of thick sedimentary depocenters.At least four proven and potential hydrocarbon source rocks contribute to oil and gas accumulations. Cretaceous oil-prone, marine source rocks, and Miocene oil- and gas-prone, paralic source rocks are well documented. We used reservoired oils, seeps, organic-rich rocks, and fluid inclusions to identify probable Jurassic hypersaline-lacustrine, and Albian carbonate source rocks. Hydrocarbon maturation began during the Early Miocene in the present-day Serrania del Interior, as the Caribbean plate moved eastward relative to South America. Large volumes of hydrocarbons expelled during this period were lost due to lack of effective traps and seals. By the Middle Miocene, however, when source rocks from the more recent foredeeps began to mature, reservoir, migration pathways, and topseal were in place. Rapid, tectonically driven burial created the opportunity for unusually efficient migration and trapping of these later-expelled hydrocarbons. The generally eastward migration of broad depocenters across Venezuela was supplemented by local, tectonically induced subsidence. These subsidence patterns and later migration resulted in the mixing of hydrocarbons from different source rocks, and in a complex map pattern of variable oil quality that was further modified by biodegradation, late gas migration, water washing, and subsequent burial.The integration of plate tectonic reconstructions with the history of source rock deposition and maturation provides significant insights into the genesis, evolution, alteration, and demise of Eastern Venezuela hydrocarbon systems. We used this analysis to identify additional play potential associated with probable Jurassic and Albian hydrocarbon source rocks, often overlooked in discussions of Venezuela. The results suggest that oils associated with likely Jurassic source rocks originated in restricted, rift-controlled depressions lying at high angles to the eventual margins of the South Atlantic, and that Albian oils are likely related to carbonate deposition along these margins, post-continental break up. In terms of tectonic history, the inferred Mesozoic rift system is the eastern continuation of the Espino Graben, whose remnant structures underlie both the Serrania del Interior and the Gulf of Paria, where thick evaporite sections have been penetrated. The pattern of basin structure and associated Mesozoic deposition as depicted in the model has important implications for the Mesozoic paleogeography of northern South America and Africa, Cuba and the Yucatan and associated new play potential.     

Hydrocarbon charging and accumulation history in the Niudong Buried Hill Field in the Baxian Depression,eastern China

The Niudong Buried Hill Field, which lies in the Baxian Depression of the Bohai Bay Basin, is the deepest oil/gas accumulation in eastern China. Its Precambrian dolomite reservoir occurs at burial depths of 5860 m–6027 m. This paper attempts to document the hydrocarbon charging and accumulation history in this field, which could greatly enhance the understanding of the mechanisms for the formation of deep hydrocarbon accumulations. Our previous study of oil trapped in fluid inclusions has demonstrated that the ratio parameters of the fluorescence spectral intensities at 425 nm and 433 nm (Q_425/433 ratio), and at 419 nm and 429 nm (Q_419/429 ratio) can be more effective for revealing hydrocarbon charging history than the previously-used fluorescence parameters such as Lambda max and red/green quotient as well as fluorescence colors. The hydrocarbon charging and accumulation history in the Niudong Buried Hill Field was studied with an integrated approach involving the application of these two spectral parameters of petroleum inclusion fluorescence as well as utilization of other data including homogenization temperatures of aqueous inclusions coeval with petroleum inclusions, and cross-cutting relationships of cements and “oil veins” in pores and fractures. The results indicate that the dolomite reservoir in the Niudong Buried Hill Field experienced three episodes of hydrocarbon charging. In the first two episodes (between 38.5Ma and 25Ma), the low mature and mature oils, which were derived from source rocks in the Sha-4 Member of the Eocene Shahejie Formation, migrated into the reservoir, but part of them leaked out due to normal faulting at the updip margin of the buried hill. These early-charged oils were preserved mainly in small pores in micritic dolomites by oil-wettability and capillary pressure. In the Neogene, the basin subsided as a whole and local faults at the updip margin became inactive and played a sealing role. By approximately 13Ma, the source rocks became highly mature and the generated hydrocarbons then migrated into the reservoir and accumulated. Therefore, the last charging is the most important for hydrocarbon accumulation in the Niudong Buried Hill Field.     

Hydrocarbon prospects across Narmada-Tapti rift in Deccan trap, central India: Inferences from integrated interpretation of magnetotelluric and geochemical prospecting studies

As the Mesozoic sediments contribute most of the oil and gas reserves of the world, we present an integrated interpretation approach using magnetotellurics (MT) and surface geochemical prospecting studies to demarcate hydrocarbon prospective Gondwana (Mesozoic) formations underneath the Deccan flood basalts of Late Cretaceous age across Narmada-Tapti rift (between Bhusawal and Barwah) in Central India. The MT interpretation shows deep (∼5 km) basement structure between southern and central part of the MT profile however, it gradually becomes shallower to either ends of the profile with a predominant basement depth reduction in the northern end compared to the southern end. The geophysical results suggest thick (2-3.5 km) Mesozoic sediments in the area characterized by deep basement structure. The geochemical analysis of the near surface soil samples indicate higher concentrations of light gaseous hydrocarbons constituents over the area marked with thick sub-basalt Mesozoic formations. Analyses of the geochemical data imply that these hydrocarbons are genetically related, generated from a thermogenic source and these samples fall in the oil-producing zone. The temperature-depth estimations in the region supports favorable temperature conditions (80-120 °C) for oil generation at basement depths.     

New insights into the carbonate karstic fault system and reservoir formation in the Southern Tahe area of the Tarim Basin

As worldwide hydrocarbon exploration has extended from shallowly to deeply buried strata, reservoir quality has attracted substantial and persistent interest in petroleum geology. In particular, deeply buried strata (>5500 m) in the Tarim Basin have attracted considerable attention because carbonate reservoirs that have experienced fracture or dissolution have also been shown to demonstrate considerable hydrocarbon potential. Therefore, it is necessary to determine how these reservoirs are developed and distributed in detail from both scientific and practical standpoints.In this paper, we address this issue using a case study in the southern Tahe area, which is contained within the largest Palaeozoic marine oilfield in China. In the northern Tahe area, mega-paleokarst systems developed in the Ordovician strata; however, the reservoir quality in the southern part of the Tahe area is relatively poor because it is covered by insoluble formations during karstification. Observations of cores and analyses of images of well logging demonstrate that these reservoirs are dominated by caves, vugs and fractures that have developed near faults. We speculate that the faults penetrating insoluble formations represent the main dissolution passages that originally developed these karstic fault systems. Additionally, we analyse a series of outcrops, seismic data, and structures to characterize the spatial geometry of these major faults and their surrounding fractures in detail. Most of these are strike-slip faults, and their subsequent reservoirs can be divided into three categories based on their development, including dendritic, sandwich and slab reservoirs. Recent studies demonstrate that karstic fault reservoirs are most common traps in the study area. Although various types of carbonate karstic fault reservoirs are represented in this region, the dendritic karstic fault reservoir is the most hydrocarbon-rich.Guided by these initial results, 108 wells were drilled from 2013 to 2014, producing 485 thousand tons of oil and yielding success ratios greater than 89%. The average production of dendritic reservoirs is 37.4 tons per day (t/d), while those of sandwich and slab types are 20.2 t/d and 14.0 t/d, respectively. These results represent significant references for future hydrocarbon exploration and the development of similar deeply buried karstic fault reservoirs in the Tarim Basin and elsewhere.     

Oil migration driven by exhumation of the Canol Formation oil shale: A new conceptual model for the Norman Wells oil field,northwestern Canada

Thermal history, petroleum system, structural, and tectonic constraints are reviewed and integrated in order to derive a new conceptual model for the Norman Wells oil field, and a new play type for tectonically active foreland regions. The thermal history recorded by Devonian rocks suggests that source rocks experienced peak thermal conditions in the Triassic–Jurassic, during which time oil was likely generated. After initial oil generation and expulsion, the Canol Formation oil shale retained a certain fraction of hydrocarbons. The shallow reservoir (650–350 m) is a Devonian carbonate bank overlain by the Canol Formation and resides within a hanging wall block of the Norman Range thrust fault. Both reservoir and source rocks are naturally fractured and have produced high API non-biodegraded oil. Thrust faults in the region formed after the Paleocene, and a structural cross-section of the field shows that the source and reservoir rocks at Norman Wells have been exhumed by over 1 km since then.The key proposition of the exhumation model is that as Canol Formation rocks underwent thrust-driven exhumation, they crossed a ductile–brittle transition zone and dip-oriented fractures formed sympathetic to the thrust fault. The combination of pore overpressure and new dip-directed subvertical fractures liberated oil from the Canol Formation and allowed for up-dip oil migration. Reservoir rocks were similarly fractured and improved permeability enhanced charging and pooling of oil. GPS and seismicity data indicate that strain transfer across the northern Cordillera is a response to accretion of the Yakutat terrane along the northern Pacific margin of North America, which is also the probable driving force for foreland shortening and rock exhumation at Norman Wells.     

Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt

The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval T_max values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).     

Petroleum generation and charge history of the northern Dongying Depression,Bohai Bay Basin,China: Insight from integrated fluid inclusion analysis and basin modelling

The petroleum generation and charge history of the northern Dongying Depression, Bohai Bay Basin was investigated using an integrated fluid inclusion analysis workflow and geohistory modelling. One and two-dimensional basin modelling was performed to unravel the oil generation history of the Eocene Shahejie Formation (Es3 and Es4) source rocks based on the reconstruction of the burial, thermal and maturity history. Calibration of the model with thermal maturity and borehole temperature data using a rift basin heat flow model indicates that the upper interval of the Es4 source rocks began to generate oil at around 35 Ma, reached a maturity level of 0.7% R_o at 31–30 Ma and a peak hydrocarbon generation at 24–23 Ma. The lower interval of the Es3 source rocks began to generate oil at around 33–32 Ma and reached a maturity of 0.7% R_o at about 27–26 Ma. Oil generation from the lower Es3 and upper Es4 source rocks occurred in three phases with the first phase from approximately 30–20 Ma; the second phase from approximately 20–5 Ma; and the third phase from 5 Ma to the present day. The first and third phases were the two predominant phases of intense oil generation.Samples from the Es3 and Es4 reservoir intervals in 12 wells at depth intervals between 2677.7 m and 4323.0 m were investigated using an integrated fluid inclusion workflow including petrography, fluorescence spectroscopy and microthermometry to determine the petroleum charge history in the northern Dongying Depression. Abundant oil inclusions with a range of fluorescence colours from near yellow to near blue were observed and were interpreted to represent two episodes of hydrocarbon charge based on the fluid inclusion petrography, fluorescence spectroscopy and microthermometry data. Two episodes of oil charge were determined at 24–20 Ma and 4–3 Ma, respectively with the second episode being the predominant period for the oil accumulation in the northern Dongying Depression. The oil charge occurred during or immediately after the modelled intense oil generation and coincided with a regional uplift and a rapid subsidence, suggesting that the hydrocarbon migration from the already overpressured source rocks may have been triggered by the regional uplift and rapid subsidence. The expelled oil was then charged to the already established traps in the northern Dongying Depression. The proximal locations of the reservoirs to the generative kitchens and the short oil migration distance facilitate the intimate relationship between oil generation, migration and accumulation.     

Temporal changes of fault seal and early charge of the Maui Gas-condensate field,Taranaki Basin,New Zealand

Fault seal due to juxtaposition or the generation of low-permeability fault rock has the potential to change through time with displacement accumulation. Temporal variations in cross-fault flow of hydrocarbons have been assessed for the Cape Egmont Fault (CEF), Taranaki Basin New Zealand, using displacement backstripping, juxtaposition and Shale Gouge Ratio (SGR) analysis. The timing of hydrocarbon migration and charge of the giant Maui Gas-condensate Field across the CEF have been assessed using seismic reflection lines (2D & 3D), coherency cubes, VShale curves from the Maui-2 well and PetroMod modelling. Displacement–backstripping analysis suggests that between the Late Miocene and early Pleistocene (5.5 and 2.1 Ma) sandstone reservoir units of the Maui Field (Mangahewa, Kaimiro and Farewell Formations) and underlying source rocks (Rakopi Formation) were partly juxtaposed across the CEF with low SGRs (< 0.2) present in the fault zone. Following 2.1 Ma SGRs increased to 0.2–0.55 adjacent to the Eocene–Palaeocene reservoir succession which was not in juxtaposed contact with source rocks. PetroMod modelling using these SGR values and juxtaposition relationships supports cross-fault flow prior to 2.1 Ma with later charge across the fault being less likely. Gas chimneys and the gas–water contact in the Eocene reservoir proximal to the fault suggest that despite limited cross-fault flow, upward leakage of hydrocarbons from the reservoir occurred after 2.1 Ma, possibly associated with active fault movement or fracturing related to faulting, and may account for the loss of an early oil phase.     

High resolution characterization of a core from the Lower Jurassic Gordondale Member,Western Canada Sedimentary Basin

The Gordondale Member is a hydrocarbon source rock and potential unconventional reservoir that extends across northeastern British Columbia and central-northwestern Alberta. It is an organic-rich, calcareous, fossiliferous mudstone with a median total organic carbon value of 6.0 wt%. A total of 230 samples were collected from approximately 25 m of Gordondale Member core for organic matter analysis using Rock-Eval 6 analysis and organic petrology. Detailed core logging provides sedimentological context for organic matter characterization. The predominant organic material in the samples is solid bitumen and liptinite with lesser zooclast and inertinite. Most kerogen is Type II, autochthonous marine biomass, with minimal dilution by inert organic carbon. Rock-Eval T_max values and random reflectance measurements of solid bitumen indicate the samples are within the oil generation window. Solid bitumen contributes a substantial amount of hydrocarbon potential to the interval. A micro-reservoir structure within the core is produced by thin intervals of impermeable displacive calcite that act as barriers to the upward migration of free hydrocarbons. These free hydrocarbon accumulations could make excellent targets for horizontal wells within the Gordondale Member.     

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.     

南堡凹陷4号构造带蛤坨断层特征与油气成藏关系

南堡凹陷4号构造带断裂发育,既发育沟通烃源岩的深断裂,也发育沟通浅层圈闭的次级断裂。综合利用地震、测井、岩性等资料分析断层的空间展布,计算蛤坨断层的生长指数和断层泥比率（SGR）,分析断层的活动性、封堵性,评价其输导性能,并结合其与烃源岩生排烃期的匹配关系研究断裂与油气运移、聚集的关系及控制规律。在典型油气藏剖面解剖的基础上,建立了4号构造带油气运聚成藏模式。     

The composition and distribution of saturated and aromatic hydrocarbons in nearshore sediments, river sediments, and coastal peat of the Alaskan Beaufort Sea: Implications for detecting anthropogenic hydrocarbon inputs

A 3-year program, to determine spatial and temporal trends in sediment concentrations of hydrocarbons and metals from oil and gas exploration and development activities, was conducted in the US Beaufort Sea. Concentrations of saturated and aromatic hydrocarbons in sediments from the Beaufort Sea were elevated in comparison to non-polluted shelf-sediments from other regions of the US coast. Potential natural sources for hydrocarbons that were examined included riverine sediments and coastal peat. Significant quantities of fossil hydrocarbons characterize the surface sediments from the entire region. Sediment inputs from river discharges appear to account for this observation. The use of source-diagnostic ratios has allowed the differentiation of various sources in an area with high naturally-occurring hydrocarbon concentrations where effects due to oil and gas exploration and development activities may be obscured.