Compaction of smectite-rich mudstone and its influence on pore pressure in the deepwater Joetsu Basin,Sea of Japan

Pore pressure prediction is needed for drilling deepwater wildcats in the Sea of Japan because it is known from past experience that there can be drilling problems can arise due to overpressure at shallow depths. The “Joetsu Basin” area is located offshore to the southwest of Sado Island on the eastern margin of the Sea of Japan. The sedimentary succession of the Neogene is mainly composed of turbidite sediments which contained smectite-rich mudstones. The cause of overpressure in the study area is expected to be a combination of mechanical disequilibrium compaction and chemical compaction, especially from the illitization of smectite.We have constructed basin models and performed numerical simulations by using 1D and 3D PetroMod to understand clearly the history of fluid flow and overpressure development in the lower Pliocene Shiya Formation and Middle to Upper Miocene Teradomari Formations. A compaction model coupled with both mechanical and chemical compaction for smectite-rich sediments is used for pore pressure calibration. We have examined three key relationships: porosity-effective stress, porosity-permeability, and the kinetics of smectite-illite transformation. We determined the ranges for the parameter values in those relationships that allow a good fit between measured and modelled pore pressures to be obtained. Results showed that for the most likely case, high pore pressure in the Lower and Upper Teradomari developed since 8.5 Ma and 5.5 Ma, respectively. Pore pressures in studied structures have approximately doubled since 1 Ma due to the high deposition rate of the Pleistocene Haizume Formation and smectite-illite transformation in the lower Pliocene-Shiya and Middle to Upper Miocene- Lower and Upperr Teradomari formations. In three cases (high case, most likely case and low case), the overpressures in the Shiya, Upper and Lower Teradomari Formations are less than 1 MPa, 15 and 30 Ma, respectively.The results provide a basis for planning future wells in the “Joetsu Basin” area and in other basins where geological conditions are similar, i.e., deepwater, high sedimentation rate, high geothermal gradient and smectite-rich sediments.     

法尔维海盆构造特征及演化

法尔维海盆位于西南太平洋海域豪勋爵海丘东侧、新喀里多尼亚岛西侧，是全球油气勘探的前沿地区。但目前对于该海盆的构造演化研究较为薄弱，限制了该海盆油气资源的进一步勘探开发。本文通过从新西兰塔斯曼海数据库搜集到大量地球物理资料，使用2D Move软件，通过平衡剖面技术进行构造演化模拟，结合区域动力学机制将海盆北部和南部的构造演化分为7个阶段:(1)早白垩世至晚白垩世陆内裂谷阶段；(2)晚白垩世断坳过渡阶段；(3)始新世早期坳陷阶段；(4)始新世晚期一次构造反转阶段；(5)始新世至渐新世热沉降阶段；(6)渐新世至中新世二次构造反转阶段；(7)中新世至今海洋沉降阶段。由于海盆中部未发现有明显的二次构造反转阶段，所以将海盆中部的构造演化划分为5个阶段:(1)早白垩世至晚白垩世陆内裂谷阶段；(2)晚白垩世断坳过渡阶段；(3)始新世早期坳陷阶段；(4)始新世晚期构造反转阶段；(5)中新世至今海洋沉降阶段。此阶段海盆整体下坳，逐渐形成现今样貌。法尔维海盆北部受到区域构造活动影响较大，白垩系地层发育较多的断裂构造；海盆中部晚白垩统地层发生较多的底辟构造；海盆南部从形成至今，受到构造活动影响较小，发育地层完整，前新生代地层较厚。整个法尔维海盆北部构造活动较强，中部较弱，南部较小。沉积地层从北到南由厚变薄。     

Compaction of diagenetically altered mudstones – Part 2: Implications for pore pressure estimation

Diagenetically altered mudstones compact mechanically and chemically. Consequently, their normal compaction trends depend upon their temperature history as well as on the maximum effective stress they have experienced. A further complication is that mudstones are commonly overpressured where clay diagenesis occurs, preventing direct observation of the hydrostatic normal compaction trend. A popular way to estimate pore pressure in these circumstances is to calculate the sonic normal compaction trend in a well with a known pressure–depth profile by applying Eaton's method in reverse, and then to estimate pore pressure in offset wells using Eaton's method conventionally. We tested this procedure for Cretaceous mudstones at Haltenbanken. The results were inconsistent because the sonic log responds differently to disequilibrium compaction overpressure and unloading overpressure, and their relative contributions vary across the basin. In theory, a two-step method using the density and sonic logs could estimate the contributions to overpressure from disequilibrium compaction and unloading. The normal compaction trend for density should be the normal compaction trend at the maximum effective stress the mudstones have experienced, not at hydrostatic effective stress. We advocate the Budge-Fudge approach as a starting point for pore pressure estimation in diagenetically altered mudstones, a two-step method that requires geological input to help estimate the overpressure contribution from disequilibrium compaction. In principle, the Budge-Fudge approach could be used to estimate the normal compaction trend for mudstones at the maximum effective stress they have experienced, and so form the basis of the full two-step method through the use of offset wells. Our initial efforts to implement the full two-step method in this way at Haltenbanken produced inconsistent results with fluctuations in estimated pore pressure reflecting some of the fluctuations in the density logs. We suspect that variations in the mineralogical composition of the mudstones are responsible.     

辽河盆地大民屯凹陷流体压力特征

大民屯凹陷是辽河断陷内4个下第三系凹陷之一。在综合利用钻井、试井及地震等资料的基础上，系统研究并论述了大民屯凹陷流体压力特征。基于57口井的声波测井资料，凹陷内泥岩压力特征可区分为正常压力、异常压力或强超压等类型；根据152口井391个点的压力测试数据，凹陷内产油层段的压力梯度多接近于1；利用公式法模拟计算了47条地震剖面的流体压力、剩余压力及压力系数的分布特征，凹陷内剖面压力系统自上而下一般由正常压力、弱超压和强超压3部分组成。此外，还根据流体压力演化的基本原理及钻井、岩性与试井等实际资料，模拟恢复了大民屯凹陷的压力演化史，其可划分为超压原始积累、超压部分释放及超压再积聚3个阶段。总体上，大民屯凹陷的超压强度低于渤海湾盆地其他地区的超压强度。     

Geochemical assessment of the Colombian oils based on bulk petroleum properties and biomarker parameters

This geochemical survey defines the typical features of representative oils from the major Colombian basins, and proposes a classification scheme useful for hydrocarbon exploration. This work is based on properties of whole oils such as API gravity, sulfur, vanadium and nickel concentrations, and gas chromatography fingerprints. The framework is completed by inclusion of biomarker parameters derived from GCMS and GCMSMS analysis.Oils from the basins of the Middle Magdalena Valley, Upper Magdalena Valley, Sinú - San Jacinto, Putumayo-Caguan, Lower Magdalena Valley and Catatumbo were assessed. Conclusions were drawn regarding possible sources of origin, oil families, degree of thermal evolution, biodegradation, mixing and refreshing, and inferences regarding exploration implications.The oils from the Middle Magdalena Valley and Upper Magdalena Valley (intermontane basins) and Putumayo (foreland basin), except those from the Caguan area, are oils with similar characteristics. In these three cases the oils are probably coming from source rocks intervals deposited in a marine Cretaceous platform, with variable carbonate/siliciclastic features. In these basins there are no oils derived from Tertiary source rocks.In Sinú-San Jacinto and Lower Magdalena Valley basins the main proportions of oils comes from very proximal environments, probably deltaic type, of Tertiary age with a minor proportion of oils coming from Cretaceous source rocks of marine anoxic environment (the only marine Cretaceous oils discovered so far in the Sinú-San Jacinto and Lower Magdalena Valley basins).The oils from Eastern Foothills of the Eastern Cordillera, look to be derived mainly from proximal Cretaceous source rocks with some mixing of oils derived from Tertiary strata. In the Catatumbo basin there are oils derived mainly from Cretaceous source rocks and some from Tertiary source rocks.Regarding the processes after entrapment, in all of the basins, the biodegradation effects were observed in varying degrees. These processes are dominant toward more quiescent regions, beyond the areas with more tectonic activity, far from the foothills of the Eastern Cordillera. Instead, close to the Eastern Cordillera are more common the paleobiodegradation processes due to reburial of younger molasses. The effects of mixing or refreshing are remarkable close to the Eastern Cordillera foothills in Llanos, Middle Magdalena Valley, and Upper Magdalena Valley basins.     

Stress and pore pressure histories in complex tectonic settings predicted with coupled geomechanical-fluid flow models

Most of the methods currently used for pore pressure prediction in sedimentary basins assume one-dimensional compaction based on relationships between vertical effective stress and porosity. These methods may be inaccurate in complex tectonic regimes where stress tensors are variable. Modelling approaches for compaction adopted within the geotechnical field account for both the full three-dimensional stress tensor and the stress history. In this paper a coupled geomechanical-fluid flow model is used, along with an advanced version of the Cam-Clay constitutive model, to investigate stress, pore pressure and porosity in a Gulf of Mexico style mini-basin bounded by salt subjected to lateral deformation. The modelled structure consists of two depocentres separated by a salt diapir. 20% of horizontal shortening synchronous to basin sedimentation is imposed. An additional model accounting solely for the overpressure generated due to 1D disequilibrium compaction is also defined. The predicted deformation regime in the two depocentres of the mini-basin is one of tectonic lateral compression, in which the horizontal effective stress is higher than the vertical effective stress. In contrast, sediments above the central salt diapir show lateral extension and tectonic vertical compaction due to the rise of the diapir. Compared to the 1D model, the horizontal shortening in the mini-basin increases the predicted present-day overpressure by 50%, from 20 MPa to 30 MPa. The porosities predicted by the mini-basin models are used to perform 1D, porosity-based pore pressure predictions. The 1D method underestimated overpressure by up to 6 MPa at 3400 m depth (26% of the total overpressure) in the well located at the basin depocentre and up to 3 MPa at 1900 m depth (34% of the total overpressure) in the well located above the salt diapir. The results show how 2D/3D methods are required to accurately predict overpressure in regions in which tectonic stresses are important.     

The Davie Fracture Zone and adjacent basins in the offshore Mozambique Margin – A new insights for the hydrocarbon potential

The interpretation of 2-D seismic reflection data provides a modern structural framework including hydrocarbon potential in the present-day stratigraphic and structural traps of both the Davie Fracture Zone and the adjacent Nacala and Angoche basins. Possible stratigraphic traps were identified in submarine fan and channel depositional environments during Cretaceous to Tertiary times. Structural traps are mostly defined within compressional structures formed by a variety of fault-related folds and rift grabens within the Jurassic and Cretaceous successions.The Nacala and Angoche basins form two depressions separated by the Davie compressional zone. This compressional structure is a prominent interior high running approximately north-south. An event of transpression and contraction characterizes the main tectonic setting commonly hosting several detached compressional structures along the western edge of the transform zone.Both basins are associated with the Late Jurassic/Early Cretaceous rifting during the opening of the Mozambique Channel. The Angoche basin is proposed here to have formed by the earliest stage of break-up in mid-Jurassic time. The basin is bounded landward by the Angoche volcanic zone, a dyke swarm branch oriented N64degE forming part of the Karoo and Dronning Maud Land magmatism at c. 180 Ma.Subsequent rifting and break-up led to the drift of East Gondwana southwards along the dextral strike-slip Davie Fracture Zone. At about 150 Ma (Tithonian), East Gondwana appears to have rotated slightly clockwise about a pivot in the proximity of the Angoche basin leading to extension and rifting in the Rovuma basin to the north of the pivot point and compression west of the Davie Fracture Zone to the south. Consequently, the eastern boundary of the Angoche basin was compressed developing a typical growth wedge of massive thrust imbrication structures while extensional tectonics created several depressions and rift-grabens forming the Nacala and Quirimbas basins.Basin stratigraphy is interpreted along seismic reflection lines and correlated to the regional stratigraphic information and wells from the Zambezi Delta and Rovuma basins.     

Transgressions of Late Cretaceous to Early Tertiary in Eastern China

ＴＲＡＮＳＧＲＥＳＳＩＯＮＳＯＦＬＡＴＥＣＲＥＴＡＣＥＯＵＳＴＯＥＡＲＬＹＴＥＲＴＩＡＲＹＩＮＥＡＳＴＥＲＮＣＨＩＮＡＱｉｕＳｏｎｇｙｕ，ＬｕＢｉｎｇｌｉ，ＣｈｅｎＹｏｎｇｃｈｅｎｇ（ＪｉｌｉｎＨｅａｄｑｕａｒｔｅｒｓＯｆＰｅｔｒｏｌｅｕｍＰｒｏｓｐ...     

The tectonics of the Okhotsk Sea

The northern and central parts of the Okhotsk Sea form an epiMesozoic platform. The hetero-aged acoustic basement is represented by deformed geosynclinal rocks from Cretaceous to Precambrian in age. The slightly deformed sedimentary cover levelled the uneven surface of the acoustic basement, and this Upper Paleogene—Neogene cover filled up the system of the structural basins. The general NW—SE and W—E extensions of the taphrogenic horsts and grabens of the acoustic basement were formed due to extension and subsidence of the earth's crust during the late Paleogene—Neogene.     

Palaeopressure reconstruction to explain observed natural hydraulic fractures in the Cleveland Basin

Natural fractures observed within the Lower Jurassic shales of the Cleveland Basin show evidence that pore pressure must have exceeded the lithostatic pressure in order to initiate horizontal fractures observed in cliff sections. Other field localities do not show horizontal fracturing, indicating lower pore pressures there. Deriving the burial history of the basin from outcrop, VR and heat-flow data gives values of sedimentation rates and periods of depositional hiatus which can be used to assess the porosity and pore pressure evolution within the shales. This gives us our estimate of overpressure caused by disequilibrium compaction alone, of 11 MPa, not sufficient to initiate horizontal fractures. However, as the thermal information shows us that temperatures were in excess of 95 °C, secondary overpressure mechanisms such as clay diagenesis and hydrocarbon generation occurred, contributing an extra 11 MPa of overpressure. The remaining 8.5 MPa of overpressure required to initiate horizontal fractures was caused by fluid expansion due to hydrocarbon generation and tectonic compression related to Alpine orogenic and Atlantic opening events. Where horizontal fractures are not present within the Lower Jurassic shales, overpressure was unable to build up as high due to proximity to the lateral draining of pressure within the Dogger Formation. The palaeopressure reconstruction techniques used within this study give a quick assessment of the pressure history of a basin and help to identify shales which may currently have enhanced permeability due to naturally-occurring hydraulic fractures.     

Neocomian to early Aptian syn-rift evolution of the normal to oblique-rifted North Gabon Margin (Interior and N'Komi Basins)

The North Gabon coastal rift basins consist of a set of 130–150 long-segment asymmetrically tilted half grabens (Interior Basin) and 000–020 short-segment en échelon half grabens (N'Komi Basin) separated by 040–060 major transverse faults. Tectono-sedimentary analysis of field and subsurface data reveals the control exerted by extensional tectonism over continental sedimentation. During Berriasian to early Barremian times, uniform uniaxial 040–060 extension was responsible for the stretching of the brittle upper crust over a 100-km wide domain. During late Barremian–early Aptian times, the main locus of extension stepped westward resulting in severe end-rift uplift and erosion of the failed Interior and N'Komi rift basins. Early Cretaceous coastal rifts in North Gabon display a wide range of styles from oblique rifting (N'Komi Basin), normal rifting (Interior Basin) to transform rifting. The pre-existing Precambrian tectonic fabric exerts a strong control over the mode and over the 100–300 km-scale segmentation of the rifting.     

The petroleum evaluation of a tectonically complex area: The western margin of the Southeast Basin (France)

The Southeast Basin of France is the thickest onshore French sedimentary basin which contains locally as much as 10 km of Mesozoic-Cenozoic sediment. Basin development occurred in several stages between late Carboniferous and late Cretaceous times. Partial tectonic inversion took place during two compressive events, the so-called ‘Pyrenean’ and ‘Alpine’ phases of late Cretaceous-early Tertiary and late Tertiary ages respectively. They are separated by an intervening stretching event of Oligocene age, which further south resulted in the opening of the western Mediterranean oceanic basin. As a result of this complex tectonic history, structural traps were difficult to image on the seismic data shot during the first phase of exploration prior to 1980. Oil and gas natural seeps, and shows in several wells, indicate that some petroleum systems are, or have been active, at least in some places.The present erosional western margin of the basin is more or less superimposed on the initial Triassic-Jurassic margin. Margin subsidence and Tertiary inversion are discussed using regional sections on which the polyphase history of the entire basin is well shown. These sections are located on three major segments where the Mesozoic margin is either partly preserved (Ardèche), or has been partly inverted in late Tertiary times (Vercors-Chartreuse), or has been completely inverted in early Tertiary times (Corbières-eastern Pyrenees). 1-D ‘Genex’ basin modelling on the Ardèche segment, and 2-D ‘Thrustpack’ structural-maturity modelling in the Vercors-Chartreuse segment are used to further assess the remaining petroleum plays.     

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.     

Hydrocarbon Potential of Pre-cenozoic Strata in the North Yellow Sea Basin

The North Yellow Sea Basin ( NYSB ), which was developed on the basement of North China (Huabei) continental block, is a typical continental Mesozoic Cenozoic sedimentary basin in the sea area. Its Mesozoic basin is a residual basin, below which there is probably a larger Paleozoic sedimentary basin. The North Yellow Sea Basin comprises four sags and three uplifts. Of them, the eastern sag is a Mesozoic Cenozoic sedimentary sag in NYSB and has the biggest sediment thickness; the current Korean drilling wells are concentrated in the eastern sag. This sag is comparatively rich in oil and gas resources and thus has a relatively good petroleum prospect in the sea. The central sag has also accommodated thick Mesozoic-Cenozoic sediments. The latest research results show that there are three series of hydrocarbon source rocks in the North Yellow Sea Basin, namely, black shales of the Paleogene, Jurassic and Cretaceous. The principal hydrocarbon source rocks in NYSB are the Mesozoic black shale. According to the drilling data of Korea, the black shales of the Paleogene, Jurassic and Cretaceous have all come up to the standards of good and mature source rocks. The NYSB owns an intact system of oil generation, reservoir and capping rocks that can help hydrocarbon to form in the basin and thus it has the great potential of oil and gas. The vertical distribution of the hydrocarbon resources is mainly considered to be in the Cretaceous and then in the Jurassic.     

Beef veins and thrust detachments in Early Cretaceous source rocks,foothills of Magallanes-Austral Basin,southern Chile and Argentina: Structural evidence for fluid overpressure during hydrocarbon maturation

We describe (1) bedding-parallel veins of fibrous calcite (beef) and (2) thrust detachments, which we believe provide good evidence for fluid overpressure in source rocks for petroleum. Our examples are from the surface or subsurface of the Magallanes-Austral Basin, which lies at the southern tip of South America. There, the best source rocks for petroleum are of Early Cretaceous age. In the central parts of the basin these source rocks have become overmature, but at the eastern edge, onshore and offshore, they are today either immature or in the oil window.In Tierra del Fuego, the foothills of the Andes consist mainly of sedimentary rocks, which have undergone thin-skinned thrusting. In the Vicuña area (Chile), Early Cretaceous source rocks have reached the surface above thrust detachments, which are visible on seismic data and well data. At the surface, we have found calcite beef, containing hydrocarbons (solid and/or fluid), in the Rio Jackson and Vicuña formations, which have reached the wet gas window. In the Rio Gallegos area (Argentina), the source rocks have not reached the surface, but seismic and well data provide good evidence for thin-skinned thrusting above flat-lying detachments in Early Cretaceous source rock, where it is in the early oil window. In contrast, there is little or no deformation where the source rock is still immature. Thus the deformation front coincides with the maturity front. Next to the central parts of the basin, where the source rocks have reached the surface within the Andes proper, they have undergone low-grade metamorphism. Within these source rocks, we have found beef veins, but of quartz, not calcite. To the east, within the foreland basin, seismic and well data provide evidence for a few compressional structures, including thin-skinned detachments in the deeply buried source rock. Finally, in the northern part of the basin (Santa Cruz province, Argentina), where it is shallower, the source rocks have reached the surface in the foothills, above a series of back-thrusts. At Lago San Martín, the source rocks have reached the oil window and they again contain calcite beef.In conclusion, where we have examined Early Cretaceous source rocks at the surface, they contain either calcite beef (if they have reached the late oil window or wet gas window) or quartz beef (if they are overmature). Independent evidence for overpressure, in the form of source-rock detachments, comes from subsurface data, especially at the southern end of the basin, where the source rocks are not overmature and deformation is relatively intense. Thus we argue that hydrocarbon generation has led to overpressure, as a result of chemical compaction and load transfer, or volume changes, or both.     

宽扎盆地油气地质特征

安哥拉宽扎盆地是典型被动大陆边缘盆地,完整经历了前裂谷阶段、裂谷阶段、过渡阶段及漂移阶段等4个构造演化阶段,形成了盐下、盐间和盐上3套沉积层序,并各自形成含油气系统。在对宽扎盆地构造演化、沉积特征及油气成藏条件进行分析后认为:宽扎盆地盐下、盐间和盐上3套沉积层序的油气成藏主控因素分别为拉伸断陷、盐隆起及盐构造运动;宽扎盆地盐下有利勘探区为盆地东部白垩系地堑构造区,盐间有利勘探区为盆地中东部盐隆发育部位,盐上有利勘探区为盆地东部古近系和新近系地堑发育部位;宽扎盆地今后勘探工作重点应放在盆地东部白垩系地堑构造区的盐下碳酸盐岩储层目标。     

黄海三大盆地的构造演化

７０年代末到８０年代中期，中国地质矿产部和中国科学院所属单位对黄海进行了大量地球物理调查和钻探，根据多道反射地震资料，浅地层剖面，重磁资料和钻探结果对黄海三大构造盆地进行地质构造学分析研究，结果表明，黄海地区三大盆地自北往南形成时代逐渐变新，构造活动性逐渐增强。     

台湾海峡地区新生代的构造演化

根据采集反射剖面,结合区域地质资料,分析了晋江凹陷、九龙江凹陷、新竹凹陷、台中凹陷和台湾凹陷为半地堑结构。新竹凹陷和台中凹陷下拗,演变为前陆盆地。晋江凹陷和九龙江凹陷因岩石圈上隆,其沉积较薄。这种模式决定了在台湾海峡地区,西部的生油气层为下第三系,而东部的生油气层为下第三系和上第三系。     

Pressure cells and pressure seals in the UK Central Graben

The Central Graben of the North Sea is characterised by high levels of overpressure (up to 40 MPa overpressure at 4500 m depth). We present pressure data for Cenozoic and Mesozoic reservoirs. Palaeocene sandstones control pressures in Tertiary mudstones and Cretaceous Chalk by acting as a regional ‘drain’. We divide the Jurassic into 18 pressure cells. The rift structure of the Graben controls the magnitude of pressure in each cell. Lateral hydraulic communication exists over 10 km distance between deeply-buried terraces (> 5000 m depth) and shallow structural highs (< 4500 m depth). Lateral communication increases pressure in the structurally-elevated sandstones to the minimum stress. This dynamic process produces zones of vertical fluid flow on the Forties-Montrose High, termed Leak Points. Vertical flow at Leak Points produces a 20 MWm⁻² heat flow anomaly and controls hydrocarbon retention. Leak Points are water-wet, while deep terraces in hydraulic communication with Leak Points are condensate-bearing. The Kimmeridge Clay Fm. forms the pressure seal in deep terraces.     

国内外深水区油气勘探新进展

深水区油气资源丰富，近年来深水油气勘探不断升温。在全球6大洲18个深水盆地中已发现约580亿桶油当量的油气资源。目前，巴西、美国墨西哥湾的深水油气田已经投入生产，而且产量不断增加，西非地区也已进入开发阶段，西北欧、地中海以及亚太地区的许多国家也都在积极开展深水油气勘探或开发。海上油气钻探不断向深水区和超深水区发展，探井数目也在继续增加，投资力度不断加强，储量每年也有很大的增长。深水油气勘探成功率平均达到30％，其中，西非的勘探成功率最高。深水区烃源岩生烃潜力较好，最好的烃源岩主要分布于侏罗系、白垩系和第三系的地层中，储层以浊积岩储层为主，盖层通常比较发育，大多数圈闭都与地层因素有关。我国南海北部陆坡深水区盆地属准被动边缘盆地，从烃源岩、储层、盖层、圈闭到运聚条件等都具备了形成大型油气田的基本地质条件，具有丰富的资源前景。