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.     

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.     

Constraining tectonic compression processes by reservoir pressure evolution: Overpressure generation and evolution in the Kelasu Thrust Belt of Kuqa Foreland Basin,NW China

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N₂k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day.     

Geochemical characteristics and isotopic reversal of natural gases in eastern Kopeh-Dagh,NE Iran

Natural gas samples from two gas fields located in Eastern Kopeh-Dagh area were analyzed for molecular and stable isotope compositions. The gaseous hydrocarbons in both Lower Cretaceous clastic reservoir and Upper Jurassic carbonate reservoir are coal-type gases mainly derived from type III kerogen, however enriched δD values of methane implies presence of type II kerogen related material in the source rock. In comparison Upper Jurassic carbonate reservoir gases show higher dryness coefficient resulted through TSR, while presence of C₁C₅ gases in Lower Cretaceous clastic reservoir exhibit no TSR phenomenon. Carbon isotopic values indicate gas to gas cracking and TSR occurrence in the Upper Jurassic carbonate reservoir, as the result of elevated temperature experienced, prior to the following uplifts in last 33–37 million years. The δ¹³C of carbon dioxide and δ³⁴S of hydrogen sulfide in Upper Jurassic carbonate reservoir do not primarily reflect TSR, as uplift related carbonate rock dissolution by acidic gases and reaction/precipitation of light H₂S have changed these values severely. Gaseous hydrocarbons in both reservoirs exhibit enrichment in C₂ gas member, with the carbonate reservoir having higher values resulted through mixing with highly-mature-completely-reversed shale gases. It is likely that the uplifts have lifted off the pressure on shale gases, therefore facilitated the migration of the gases into overlying horizons. However it appears that the released gases during the first major uplift (33–37 million years ago) have migrated to both reservoirs, while the second migrated gases have only mixed with Upper Jurassic carbonate reservoir gases. The studied data suggesting that economic accumulations of natural gas/shale gases deeper than Upper Jurassic carbonate reservoir would be unlikely.     

Khasib and Tannuma oil sources, East Baghdad oil field, Iraq

This work presents new insights of the generation, quality and migration pathways of the hydrocarbons in the East Baghdad Oil Field.The Khasib and Tannuma formations in East Baghdad are considered as oil reservoirs according to their high porosity (15-23%) and permeability (20-45 mD) in carbonate rocks. The hydrocarbons are trapped by structural anticline closure trending NW-SE. Gas chromatography analysis on these oil reservoirshave shown biomarkers of abundant ranges of n-alkanes of less than C22 (C17-C21) with C19 and C18 peaks. This suggests mainly liquid oil constituents of paraffinic hydrocarbons from marine algal source of restricted palaeoenvironments in the reservoir. The low non aromatic C15 + peaks are indicative for slight degradation and water washing. Oil biomarkers of Pr./Ph. = 0.85, C31/C30 < 1.0, location in triangle of C27-C29 sterane, C28/C29 of 0.6 sterane, Oleanane of 0.01 and CPI = 1.0, indicate an anoxic marine environment with carbonate deposits of Upper Jurassic to Early Cretaceous age. Four Miospores, seven Dinoflagellates and one Tasmanite species confirm affinity to the upper most Jurassic to Lower Cretaceous Chia Gara and Ratawi Formations.The recorded palynomorphs from the Khasib and Tannuma Formations are of light brown color of TAI = 2.8-3.0 and comparable to the mature palynomorphs that belong to the Chia Gara and the Lower part of Ratawi Formations.The Chia Gara Formation generated oil during Upper Cretaceous to Early Palaeogene and accumulated in structural traps of Cretaceous age, such as the Khasib and Tannuma reservoirs. The Chia Gara Formation generated and expelled high quantities of oil hydrocarbons according to their TOC wt% of 0.5-8.5 with S2 = 2.5-18.5 mg Hc/g Rock, high hydrogen index of the range 150-450 mg Hc/g Rock, good petroleum potential of 4.5-23.5 mg Hc/g Rock, mature (TAI = 2.8-3.0 and T_max = 428-443C), kerogen type II and palynofacies parameters of up to 100% AOM (Amorphous Organic Matters). This includes algae deposits in a dysoxic-anoxic to suboxic-anoxic environment.Alternative plays are discussed according to the migration pathways.     

Hydrocarbon evolution for a north-south section of the South Caspian Basin

A 150 km length, 6-second deep, seismic line across the west central and north parts of the South Caspian Basin was used to construct quantitative dynamical, thermal and hydrocarbon evolution patterns. The depth of the west part of the 2-D section of the South Caspian Basin is almost 30 km. The computer program GEOPETII was used to provide quantitative evolution models. The procedure provided an opportunity to investigate the development dynamics of: excess fluid pressure, porosity retention, rock fracturing, compaction, heat transfer, maturity, generation pressure, kinetic hydrocarbon generation, migration and accumulation, together with solubility effects on hydrocarbon transport. The results suggest that: (i) Temperature is 350–400°C in the deepest part of the section at a depth of 26–29 km; (ii) The highest values of excess pressure nearly twice hydrostatic fluid pressure are in Jurassic and Cretaceous formations in the west part of the section, which has now subsided to a depth of about 20–27 km; (iii) Major oil and gas generation began in the last 10-5 MYBP, the migration in free-phase and in water solution occurring dominantly in the last few million years; (iv) Trapping of hydrocarbons took place mainly, but not exclusively, in the 3–9 km depth interval in the sands of the Productive Series of the Pilocene, embedded in a shale sequence; (v) Oil and gas filling of the shallow reservoirs by oil and gas is on-going today, indicating an extremely high productivity for any reservoir found in the offshore area; (vi) There is overlap with depth of oil and gas reservoirs, and the total amount of hydrocarbons estimated to be trapped is considerable; (vii) The high overpressure expected makes for a drilling hazard, but one which it is worthwhile to overcome if the anticipated oil and gas accumulations are encountered.     

古巴前陆盆地三区块石油地质特征及勘探潜力分析

古巴三区块是2005年中国石化获得的风险勘探开发合同区块,位于墨西哥湾西南部,是古巴西部的前陆盆地之一。结合该盆地勘探现状,对相关的钻井、物探以及地球化学等资料进行石油地质综合分析,评价了该盆地的油气成藏条件及其勘探潜力,预测了有利区带。三区块主要发育上侏罗统一下白垩统的泥灰岩、泥质灰岩和中-下侏罗统泥页岩两套主要烃源岩,储层以泥晶灰岩、灰岩和砂砾岩为主,区内早期形成的圈闭在造山期基本遭到破坏,有效的圈闭主要形成于晚古近纪,圈闭类型有背斜、断鼻、断块和地层圈闭等,推测可能发育多套储盖组合。据区域对比和钻井资料分析,区内的前陆冲断带是本区最有利勘探区带,南盆地北缘发育较厚的第三系,推测是本区有利远景区。     

Formation of low permeability reservoirs and gas accumulation process in the Daniudi Gas Field,Northeast Ordos Basin,China

The Daniudi Gas Field is a typical large-scale coal-generated wet gas field located in the northeastern Ordos Basin that contains multiple Upper Paleozoic gas-bearing layers and considerable reserves of gas. Based on integrated analysis of reservoir petrology, carbonate cement C–O isotope, geochemistry of source rocks and HC gas and numerical basin modeling, a comprehensive study focusing on the formation of low permeability reservoirs and gas generation process uncovers a different gas accumulation scene in Daniudi Gas Field. The gas accumulation discovered was controlled by the reservoir permeability reduction and gas generation process, and can be divided into two distinct stages by the low permeability reservoir formation time: before the low permeability reservoir formation, the less matured gas was driven by buoyancy, migrated laterally towards NE and then accumulated in NE favorable traps during Late Triassic to early Early Cretaceous; after the low permeability reservoir formation, highly matured gas was driven by excessive pressure, migrated vertically and accumulated in-situ or near the gas-generating centers during early to late Early Cretaceous. The coupling relationship between reservoir diagenetic evolution and gas generation process controlled on gas accumulation of the Daniudi Gas Field. This study will aid in understanding the gas accumulation process and planning further E&D of the Upper Paleozoic super-imposed gas layers in the whole Ordos Basin and other similar super-imposed low permeability gas layer basins.     

琼东南盆地深水区L18气田上新统地层圈闭气田形成条件及成藏模式

近期在琼东南盆地超深水区发现了L18气田上新统地层圈闭气田,但在聚气背景、烃源岩、储层沉积成因及天然气输导体系等气田形成条件和成藏模式认识存在争议。通过对该气田形成条件的综合分析,认为上新世轴向古洼槽内地层圈闭、陵水凹陷东洼下渐新统崖城组浅海相烃源岩、上新统限制型重力流砂岩储层和渐新统-中新统断裂垂向沟源通道是形成上新统地层圈闭气田的4个基本条件。中中新世以来盆地中央继承性发育轴向古洼槽和限制型重力流沉积,随着后期地层沉积迁移、差异压实作用,上新统莺歌海组砂岩顶面在轴向洼槽内起伏,并被周边泥岩封盖、封堵,形成了地层圈闭;约3.4 Ma BP,陵水凹陷东洼下渐新统崖城组浅海相烃源岩生成了成熟天然气,沿渐新统-中新统断裂向上运移到上新统莺歌海组重力流沉积砂岩中,再侧向运移至地层圈闭中聚集成藏,具有"烃源岩、圈闭、断裂+砂岩输导层"三要素控藏的上新统地层圈闭成藏模式。     

A well-preserved 250 million-year-old oil accumulation in the Tarim Basin,western China: Implications for hydrocarbon exploration in old and deep basins

A giant oilfield (YM-2) with an estimated reserve of close to one billion bbl was recently discovered in an Ordovician carbonate reservoir at a burial depth of 5800–6200 m in the northern Tarim Basin, western China. Biomarker and isotope geochemistry of the hydrocarbons indicate that the oil was derived from Ordovician marine source rocks at early to peak oil generation. Authigenic illite (K–Ar) dating, fluid inclusion analysis, fluid inclusion PVTx and thermal history modeling indicate that the accumulation is of primary in origin, and the original charge occurred in the Permian during the Late Hercynian Orogenic Stage, approximately 290–250 million years ago. The physiochemical compositions of the hydrocarbons and formation water remained largely unchanged since the initial accumulation. The excellent preservation of such an old accumulation at such a great depth is due to continuous burial of the YM-2 structure since the Triassic, a thick effective seal, and a relatively low geothermal gradient with a current reservoir temperature of 127–130 °C. This finding suggests that under suitable conditions old petroleum accumulations can be well-preserved, and some old and deep basins may be prospective frontiers for future exploration.     

Structural styles and tectonic evolution of the Seram Trough, Indonesia

The Seram Trough is located in the northern part of the Banda Arc-Australian collision zone in eastern Indonesia and is currently the site of contraction between the Bird's Head of New Guinea and Seram Island. It has been interpreted as a subduction trench, an intra-continental thrust zone and foredeep, and a zone of strike-slip faulting. Recently acquired 2D seismic lines clarify its tectonic evolution and relationship to the Bird's Head. Folding in the Early Pliocene formed an anticlinorium running from Misool to the Onin Peninsula of Irian Jaya and produced a newly recognised angular unconformity. The unconformity truncates sediments as old as Middle Jurassic and is an ancient topographic surface with significant relief. It was later folded and now dips south towards the trough where it is covered by up to 3 km of sediments. Initial tilting of the unconformity surface was accompanied by deposition of a transgressive sequence which can be traced into the trough. This is overlain by two sequences which prograde towards the trough. These sequences show progressive rotation of the unconformity surface, gravitational displacement of sediments into the trough, and thrusting which continues to the present day. Contraction occurred in the trough after the Early Pliocene and is younger than the previously suggested Late Miocene age. Thrust faults in the trough deform sediments deposited above the unconformity and detach at the unconformity surface. On Seram thrust faults repeat Mesozoic–Miocene sequences and probably detach at their contact with metamorphic basement. The detachment surface must cut through the Mesozoic-Miocene sequence between Seram and the trough. This work suggests the Seram Trough is not a subduction trench but a foredeep produced in response to loading by the developing fold and thrust belt of Seram, with an associated peripheral bulge to the north. The Seram Trough is interpreted to be a very young zone of thrusting within the Australian continental margin.     

深水褶皱冲断带的构造变形和油气地质特征

深水褶皱冲断带是目前全球油气勘探的重要领域,其构造变形和油气地质特征是勘探研究的主要内容。通过对不同地区深水褶皱冲断带的地震剖面解释和综合分析,结合沉积特征对其构造样式、变形特征和石油地质特征进行了研究。研究表明,在主动大陆边缘和被动大陆边缘存在4种不同构造样式的深水褶皱冲断带,即:主动大陆边缘型深水褶皱冲断带;被动大陆边缘背景下的泥岩滑脱型、盐岩滑脱型和重力垮塌滑动型深水褶皱冲断带。由于他们具有不同的驱动机制、构造特征和演化特征,导致了其含油气性差别较大。主动大陆边缘背景下发育的深水褶皱冲断带主要发育倾向陆地的逆冲断层、叠瓦构造以及相关的褶皱构造,缺乏有效的烃源岩和储层。被动大陆边缘背景下发育的深水褶皱冲断带可以划分为伸展区、过渡区和挤压区3部分,并发育相关构造,其中泥岩滑脱型和盐岩滑脱型深水褶皱冲断带已经有大量的油气发现。     

Generation characteristics of Mesozoic syn- and post-rift source rocks,Bonaparte Basin,Australia: New insights from compositional kinetic modelling

Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage.     

A sub-salt structural model of the Kelasu structure in the Kuqa foreland basin,northwest China

The Kuqa foreland basin, adjacent to the South Tianshan Mountains, is a major hydrocarbon accumulation basin in Western China. The Kelasu structural belt is the focus for hydrocarbon exploration in the basin due to the presence of ramp-related anticline traps and a thick salt seal. The model of the Kelasu sub-salt structure is still contentious because of the structural complexity and poor seismic imaging below the salt layer. The area–depth–strain (ADS) method is applied to the southern part of the Kelasu Fault, a regional fault that cuts basement rocks. The ADS results are consistent with the seismic data, which indicate that both thin-skinned thrusting and basement-involved deformation occur within the Kelasu structure, with the Kelasu Fault acting as the boundary between the two regions of contrasting deformation. The ADS results also suggest that the depth of the lower detachment of the thin-skinned thrust belt is 9.5–10 km, which may correspond to the base of the Triassic. The Kelasu structure has undergone approximately 8.15–10.76 km of horizontal shortening in the east and 16.34 km in the west of the structure.     

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.     

Tectonic evolution of the internal sector of the Central Apennines, Italy

A wide sector of the internal portion of the Central Apennines, which comprises the southern Lepini Mtns up to the northern Simbruini Mtns has been investigated through detailed field mapping and integrated with structural analyses. A few small productive oil fields and a large number of hydrocarbon seeps and oil impregnations are located in this sector. This area offers good opportunities for testing the use of structural fieldwork methodologies in order to highlight oil migrating paths, from Triassic source rocks, and prospecting chances for oil field exploitation.The main stages of the structural evolution of the area took place after deposition of the foredeep sediments (Frosinone Fm.), i.e. after Late Tortonian, under a stress field characterised by a NE–SW trending σ₁, which was responsible for the early emplacement of major thrust faults present in the area. The Messinian-Early Pliocene thrust-top basin deposits allowed the reconstruction of an in-sequence evolution of the thrust system. The development of out-of-sequence thrusting post-dates these structures leading to a further strong shortening phase in the area during the Pliocene. This phase is characterised by a roughly NNE–SSW trending σ₁. Some peculiar tectonic features evidenced by thrust faults with younger-over-older relationships and an inversion of the original stacking of thrust sheets developed during this phase.Successively, a block-faulting tectonic, mainly with NE–SW extension stress field, occurred and dismembered the compressive tectonic edifice.Later on up to the Middle Pleistocene, N–S to NNE–SSW trending dextral strike-slip faults also acted in the area. Associated to the strike-slip tectonics are local volcanic centres as well as necks, whose compositions show a mantle origin, thus indicating deep seating and a possible lithospheric significance of these structures.In the light of this study, the reduced extension of the productive oil area as well as the spotting of oil seeps, may indicate that the migration conditions are not tied to well defined structures but that likely the cross-cutting points among structures facilitate the conditions for an upwards rising of oil. These conditions in particular are achieved at least in two cases: (1) where the Late Triassic source rocks do not have great depth due to normal or reverse faults, or (2) at a major depth when encountered by transcurrent-oblique roughly N–S trending faults—in both cases oil can easily migrate along the damage zone associated to the fault plane.     

文卫濮结合部沙二下亚段滚动勘探目标评价

针对文卫濮结合部沙二下亚段潜在油气资源量大,而探明程度相对较低的地质特点,对目标区进行了整体构造格局、局部构造特征、砂体和储层物性展布状况,以及油气聚集成藏条件的研究.认为研究区为反向屋脊式半背斜断块圈闭,是非常有利的油气成藏单元;沙二下亚段储层在构造高部位十分发育且物性较好;柳屯凹陷和马寨次洼沙三、沙四段生成的油气沿文西断层向上运移到沙二下亚段储集层,沙一段及沙二上亚段稳定发育的大套泥岩是封盖能力很强的盖层,从而形成了下生、中储、上盖的成藏组合.根据研究成果指出了多个有利勘探目标,为下一步沙二下亚段滚动勘探提供了建议.     

Tracing of deeply-buried source rock: A case study of the WC9-2 petroleum pool in the Pearl River Mouth Basin, South China Sea

The identification of a deeply-buried petroleum-source rock, owing to the difficulty in sample collection, has become a difficult task for establishing its relationship with discovered petroleum pools and evaluating its exploration potential in a petroleum-bearing basin. This paper proposes an approach to trace a deeply-buried source rock. The essential points include: determination of the petroleum-charging time of a reservoir, reconstruction of the petroleum generation history of its possible source rocks, establishment of the spatial connection between the source rocks and the reservoir over its geological history, identification of its effective source rock and the petroleum system from source to trap, and evaluation of petroleum potential from the deeply-buried source rock. A case study of the W9-2 petroleum pool in the Wenchang A sag of the Pearl River Mouth Basin, South China Sea was conducted using this approach. The W9-2 reservoir produces condensate oil and gas, sourced from deeply-buried source rocks. The reservoir consists of a few sets of sandstone in the Zhuhai Formation, and the possible source rocks include an early Oligocene Enping Formation mudstone and a late Eocene Wenchang Formation mudstone, with a current burial depth from 5000 to 9000 m. The fluid inclusion data from the reservoir rock indicate the oil and the gas charged the reservoir about 18–3.5 Ma and after 4.5 Ma, respectively. The kinetic modeling results show that the main stages of oil generation of the Wenchang mudstone and the Enping mudstone occurred during 28–20 Ma and 20–12 Ma, respectively, and that the δ¹³C₁ value of the gas generated from the Enping mudstone has a better match with that of the reservoir gas than the gas from the Wenchang mudstone. Results from a 2D basin modeling further indicate that the petroleum from the Enping mudstone migrated upward along the well-developed syn-sedimentary faults in the central area of the sag into the reservoir, but that the petroleum from the Wenchang mudstone migrated laterally first toward the marginal faults of the sag and then migrated upward along the faults into shallow strata. The present results suggest that the trap structure in the central area of the sag is a favorable place for the accumulation of the Enping mudstone-derived petroleum, and that the Wenchang mudstone-derived petroleum would have a contribution to the structures along the deep faults as well as in the uplifted area around the sag.     

北部湾盆地涠西南凹陷油气成藏条件分析

涠西南凹陷位于北部湾盆地西南部,发育有多个油气田(含油气构造)。以油气地质理论为指导,在构造和沉积地层特征研究的基础上,重点分析了烃源岩、储集层、圈闭及输导介质等油气成藏的基本要素,认为涠西南凹陷拥有较好的烃源岩、发育多套储集层、多种类型圈闭和复合的输导介质,具备油气藏形成的基本条件,具有广阔的油气勘探前景。     

南海深水盆地油气地质特征及勘探方向

在深入调研南海深水盆地油气地质条件的基础上,系统分析了油气分布规律和成藏主控因素,明确了油气资源潜力和有利勘探方向,旨在为南海深水油气勘探决策提供科学依据.研究结果表明:南海深水盆地发育在非典型边缘海大陆边缘,其石油地质条件具有特殊性,油气分布特征存在显著的南北差异.其中,南海北部深水的珠江口盆地和琼东南盆地,以构造圈...