Depositional and Diagenetic History and Petroleum Geology of the Jurassic Norphlet Formation of the Alabama Coastal Waters Area and Adjacent Federal Waters Area

The discovery of deep (20,000 ft) gas reservoirs in eolian sandstone of the Upper Jurassic Norphlet Formation in Mobile Bay and offshore Alabama in the late 1970s represents one of the most significant hydrocarbon discoveries in the nation during the past several decades. Estimated original proved gas from Norphlet reservoirs in the Alabama coastal waters and adjacent federal waters is 7.462 trillion ft3 (Tcf) (75% recovery factor). Fifteen fields have been established in the offshore Alabama area. Norphlet sediment was deposited in an arid environment in alluvial fans, alluvial plains, and wadis in updip areas. In downdip areas, the Norphlet was deposited in a broad desert plain, with erg development in some areas. Marine transgression, near the end of Norphlet deposition, resulted in reworking of the upper part of the Norphlet Formation. Norphlet reservoir sandstone is arkose and subarkose, consisting of a simple assemblage of three minerals, quartz, albite, and K-feldspar. The present framework grain assemblage of the Norphlet is dominantly diagenetic, owing to albitization and dissolution of feldspar. Despite the simple framework composition, the diagenetic character of the Norphlet is complex. Important authigenic minerals include carbon ate phases (calcite, dolomite, Fe-dolomite, and breunnerite), feldspar (albite and K-feldspar), evaporite minerals (anhydrite and halite), clay minerals (illite and chlorite), quartz, and pyrobitumen. The abundance and distribution of these miner als varies significantly between onshore and offshore regions of Norphlet production. The lack of sufficient internal sources of components for authigenic minerals, combined with unusual chemical compositions of chlorite (Mg-rich), breunnerite, and some minor authigenic minerals, suggests that Louann-derived fluids influenced Norphlet diagenesis. In offshore Alabama reservoirs, porosity is dominantly modified primary poros ity. Preservation of porosity in deep Norphlet reservoirs is due to a combination of factors, including a lack of sources of cement components and lack of pervasive early cement, so that fluid-flow pathways remained open during burial. Below the dominantly quartz-cemented tight zone near the top of the Norphlet, pyrobitumen is a major contributor to reduction in reservoir quality in offshore Alabama. The highest reservoir quality occurs in those wells where the present gas water contact is below the paleohydrocarbon water contact. This zone of highest reservoir quality is between the lowermost occurrence of pyrobitumen and the present gas water contact.     

南黄海盆地及邻区中生代地层对比

中生代地层广泛分布于南黄海盆地及邻区，包括胶莱盆地、苏北盆地、群山盆地、黑山盆地、庆尚盆地等。陆上和海域的三叠纪地层主要由灰岩组成。侏罗纪地层目前只发现陆上，主要由陆相碎屑岩组成，但从南黄海盆地某些地震剖面上可以看出，海域侏罗纪地层很可能存在。白垩纪地层在上述中生代盆地中分布最广，在许多钻井中，白垩纪地层的厚度在1000m以上，甚至2000m。其中，陆地上早白垩纪地层主要由暗色陆相碎屑岩组成，例如胶莱盆地的莱阳组、苏北盆地的葛村组，庆尚盆地的新洞群；而海域的早白垩纪地层通常由红色碎屑岩组成，例如，南黄海盆地东侧的Kachi-1和Inga-1井钻遇早白垩纪地层，其中Kachi-1井的早白垩纪地层为红褐色碎屑岩夹火山岩，而Inga-1井的早白垩纪地层为玄武岩。中白垩纪地层属氧化环境，岩石通常为红色或棕色。例如，胶莱盆地的王氏组、苏北盆地的浦口组和赤山组、庆尚盆地的河阳群。在南黄海盆地中，ZC7－2－1、Kachi-1和另外5口井均钻遇这套以红色为主的地层。苏北盆地和南黄海盆地的晚白垩纪地层称为泰州组，主要由暗色泥岩组成，而庆尚盆地的晚白垩纪地层称为榆川群，主要由火山岩组成。地层对比显示，南黄海盆地及邻区中生代地层具有东部沉积厚、西部沉积薄，东部沉积环境以氧化为主、岩石发红，西部以还原环境为主、岩石发暗，东部以火山岩为主、西部以碎屑岩为主的特征。     

山东及皖北上侏罗统及与邻区对比的大地构造意义

通过对研究区中生代地层典型剖面或代表性剖面系统考察和综合研究,对上侏罗统及其上覆、下伏岩石地层进行进一步系统清理和修订：（1）将济阳坳陷原上侏罗统蒙阴组划归下白垩统,与之相对应的是鲁西南地区为杨家庄组;将山东地区中—上侏罗统三台组界定为中侏罗统;（2）将皖北地区合肥盆地圆筒山组划入中—上侏罗统;原上侏罗统周公山组认为是跨时代地层单元（J3K1）。（3）大别山北麓北淮阳六安、金寨地区的凤凰台组、三尖铺组定为晚侏罗世早期。在此基础上建立了中国东部地区准确可行的地层对比关系,提出了与国际接轨的地层划分与对比表。对比结果表明中国东部晚侏罗世除了在南北缘存在沉积外,整个地区缺失上侏罗统。该现象表明中国东部在晚侏罗世仍为挤压应力环境甚至比早中侏罗世更为强烈,甚至一直维持到早白垩世初。     

Impact of basin structure and evaporite distribution on salt tectonics in the Algarve Basin,Southwest Iberian margin

The SW Iberian margin developed as a passive margin during Mesozoic times and was later inverted during the mainly Cenozoic Alpine orogeny. The initial syn-rift deposits include a Lower Jurassic evaporite unit of variable thickness. In the onshore, this unit is observed to thicken basinward (i.e., southward), in fault-controlled depocenters, and salt-related structures are only present in areas of thick initial evaporites. In the offshore, multiple salt-structures cored by the Lower Jurassic evaporites are interpreted on seismic reflection data and from exploratory drilling. Offshore salt structures include the allochthonous Esperança Salt Nappe, which extends over an area roughly 40 × 60 km. The abundance of salt-related structures and their geometry is observed to be controlled by the distribution of evaporite facies, which is in turn controlled by the structure of rift-related faulting. This paper presents a comprehensive study of salt tectonics over the entire onshore and offshore SW Iberian passive margin (southern Portugal and Gulf of Cadiz), covering all aspects from initial evaporite composition and thickness to the evolution of salt-related structures through Mesozoic extension and Cenozoic basin inversion.     

Middle and Upper Jurassic hydrocarbon potential of the Zagross Fold Belt,North Iraq

Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian–Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian – Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic – Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq.Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C₂₈/C₂₉ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field.Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability.These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq.     

The Lower Cretaceous succession of the northwestern Barents Shelf: Onshore and offshore correlations

The Lower Cretaceous succession in the Barents Sea is listed as a potential play model by the Norwegian Petroleum Directorate. Reservoirs may occur in deep to shallow marine clastic wedges located in proximity to palaeo-highs and along basin margins. In addition, shelf-prism-scale clinoforms with high amplitude anomalies in their top- and bottomsets have been reported from reflection seismic but they have never been drilled. In Svalbard, the exposed northwestern corner of the Barents Shelf, Lower Cretaceous strata of shelfal to paralic origin occur, and includes the Rurikfjellet (Valanginian–Hauterivian/lowermost Barremian), Helvetiafjellet (lower Barremian–lower Aptian) and Carolinefjellet formations (lower Aptian–middle Albian). By combining sedimentological outcrop studies and dinocyst analyses with offshore seismic and well ties, this study investigate the link between the onshore strata and the offshore clinoforms. Age-vise, only three (S1–S3) of the seismic sequences defined in the offshore areas correlate to the onshore strata; S1 correspond to the Rurikfjellet Formation, S2 to the Helvetiafjellet Formation and the lower Carolinefjellet Formation, and S3 to the upper Carolinefjellet Formation. Offshore, all three sequences contain generally southward prograding shelf-prism-scale clinoforms. A lower Barremian subaerial unconformity defines the base of the Helvetiafjellet Formation, and its extent indicates that most of the Svalbard platform was exposed and acted as a bypass zone in the early Barremian. Onshore palaeo-current directions is generally towards the SE, roughly consistent with the clinoform accretion-direction towards the S. The local occurrence of a 150 m thick succession of gravity flow deposits transitionally overlain by prodelta slope to delta front deposits in the Rurikfjellet Formation, may indicate that shelf-edges also developed in Svalbard. The late Hauterivian age of theses deposits potentially highlights the inferred offlapping nature of the Lower Cretaceous strata as they predate the lower Barremian unconformity, and thus record a hitherto unknown regression in Svalbard. The presence of the lower Barremian subaerial unconformity in Svalbard, the general southeastward palaeo-current directions, and the age-equivalent clinoform-packages south of Svalbard, suggests that the onshore and offshore strata is genetically linked and was part of the same palaeo-drainage system.     

Petroleum retention in the Mandal Formation,Central Graben,Norway

Upper Jurassic organic matter-rich, marine shales of the Mandal Formation have charged major petroleum accumulations in the North Sea Central Graben including the giant Ekofisk field which straddles the graben axis. Recent exploration of marginal basin positions such as the Mandal High area or the Søgne Basin has been less successful, raising the question as to whether charging is an issue, possibly related to high thermal stability of the source organic matter or delayed expulsion from source to carrier.The Mandal Formation is in part a very prolific source rock containing mainly Type II organic matter with <12 wt.-% TOC and HI < 645 mg HC/g TOC but Type III-influenced organofacies are also present. The formation is therefore to varying degrees heterogeneous. Here we show, using geochemical mass balance modelling, that the petroleum expulsion efficiency of the Mandal Formation is relatively low as compared to the Upper Jurassic Draupne Formation, the major source rock in the Viking Graben system. Using maturity series of different initial source quality from structurally distinct regions and encompassing depositional environments from proximal to distal facies, we have examined the relationship between free hydrocarbon retention and organic matter structure. The aromaticity of the original and matured petroleum precursors in the Mandal source rock plays a major role in its gas retention capacity as cross-linked monoaromatic rings act on the outer surface of kerogen as sorptive sites. However, oil retention is a function of both kerogen and involatile bitumen compositions. Slight variations in total petroleum retention capacities within the same kerogen yields suggest that texture of organic matter (e.g. organic porosity) could play a role as well.     

Chemostratigraphy of upper Jurassic reservoir sandstones,Danish Central Graben,North Sea

A chemostratigraphic study of Upper Jurassic sandstones in the northern Danish Central Graben has been undertaken within the framework of a well-defined stratigraphic/sedimentological model based particularly on cored well sections. Two reservoir sandstone units are recognised, the transgressive marginal marine to shoreface sandstone of the Gert Member and the regressive to transgressive shoreface sandstone of the Ravn Member. Both members belong to the Heno Formation, which is equivalent to the Fulmar Formation (UK) and the Ula Formation (Norway).     

Connecting Onshore and Offshore Near-Surface Geology: Delaware's Sand Inventory Project

Beginning in 1988, the Delaware Geological Survey began a program to inventory on-land sand resources suitable for beach nourishment. The inventory included an assessment of the native beach textures using existing data and developing parameters of what would be considered suitable sand textures for Delaware's Atlantic beaches. An assessment of the economics of on-land sand resources was also conducted, and it was determined that the cost of the sand was competitive with offshore dredging costs. In addition, the sand resources were put into a geologic context for purposes of predicting which depositional environments and lithostrati graphic units were most likely to produce suitable sand resources. The results of the work identified several suitable on-land sand resource areas in the Omar and Beaverdam formations that were deposited in barrier-tidal delta and fluvial-estuarine environments, respectively. The identified on-land resources areas have not been utilized due to difficulties of truck transport and development pressures in the resource areas. The Delaware Geological Survey's participation in years 8, 9, and 10 of the Continental Margins Program was developed to extend the known resource areas onshore to offshore Delaware in order to determine potential offshore sand resources for beach nourishment. Years 8 and 9 involved primarily the collection of all available data on the offshore geology. These data included all seismic lines, surface grab samples, and cores. The data were filtered for those that had reliable locations and geologic information that could be used for geologic investigations. Year 10 completed the investigations onshore by construction of a geologic cross-section from data along the coast of Delaware from Cape Henlopen to Fenwick. This cross section identified the geologic units and potential sand resource bodies as found immediately along the coast. These units and resources are currently being extended offshore and tied to known and potential sand resources as part of the continuing cooperative effort between the Delaware Geological Survey and the Minerals Man agement Service's INTERMAR office as sand resources are identified in federal waters off Delaware. Offshore sand resources are found in the Pliocene Beaverdam Formation offshore where overlying Quaternary units have been stripped, in the tidal delta complexes of several Quaternary units likely equivalent to the onshore Omar Formation, and in late Pleistocene and Holocene-age shoal complexes. Onshore lithostratigraphic units can be traced offshore and show another reason for continued geologic mapping both onshore and offshore.     

Segmentation and differential post-rift uplift at the Angola margin as recorded by the transform-rifted Benguela and oblique-to-orthogonal-rifted Kwanza basins

We analyse tectonic and sedimentary field and subsurface data for the Angola onshore margin together with free-air gravity anomaly data for the offshore margin. This enables us to characterize the mode of syn-rift tectonism inherited from the Precambrian and its impact on the segmentation of the Angola margin. We illustrate that segmentation by the progressive transition from the Benguela transform-rifted margin segment to the oblique-rifted South Kwanza and orthogonal-rifted North Kwanza margin segments. The spatial variation in the intensity of post-rift uplift is demonstrated by the study of a set of geomorphic markers detected in the post-rift succession of the coastal Benguela and Kwanza Basins: Upper Cretaceous to Cenozoic uplifted palaeodeltas, erosional unconformities, palaeovalleys, Quaternary marine terraces and perched Gilbert deltas. The onshore Benguela transform margin has a distinctive, mainly progradational stratigraphic architecture with long-term sedimentary gaps and high-elevation marine terraces resulting from moderate Upper Cretaceous–Cenozoic to major Quaternary uplifting (i.e. 775–1775 mm/ky or m/Ma). By contrast, repeated synchronous episodes of minor Cenozoic to Quaternary uplift occurred along the orthogonal-rifted North Kwanza segment with its Cenozoic aggradational architecture, short-term sedimentary gaps and low-elevation Pleistocene terraces. Margin style likewise governs spatial variations in the volume of offshore sediment dispersed in the associated deep-sea fans. Along the low-lying North Kwanza margin, sedimentation of the broad Cenozoic to Pleistocene Kwanza submarine fan was probably governed by the width of the Kwanza interior palaeodrainage basin combined with the wet tropical Neogene climate. Along the high-rising Benguela margin, the small size of the Benguela deep-sea fan is related to the interplay between moderate continental sediment dispersal from long-lived small catchments and a warm, very arid Neogene climate. However, the driving forces behind the epeirogenic post-rift uplift of the Angola coastal bulge remain a matter of speculation.     

Jurassic source rocks in the Vienna Basin (Austria): Assessment of conventional and unconventional petroleum potential

The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m²). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.     

华南陆缘中生界烃源岩条件评价

华南陆缘出露的上三叠统-白垩系,累计厚度超过10 000m,露头调查未见油苗,烃源岩主要为泥岩、碳质泥岩和煤线,有机质类型以Ⅱ-Ⅲ型为主。上三叠统小水组,发育较深水的海相、Ⅱ型良好烃源岩,TOC为1.17%～5.43%;下侏罗统桥源组发育海陆过渡环境的Ⅲ型良好烃源岩,TOC为1.36%～10.37%;下侏罗统其他层系(金鸡组、银瓶山组、上龙水组、长埔组、吉水门组)发育浅海-半深海相的中等-好的烃源岩,TOC为0.5%～1.76%。烃源岩均已处于成熟-过成熟阶段。小水组、蓝塘群烃源岩品质良好,厚度巨大,在南海北部海域开展中生界烃源岩研究时,值得重点关注是否有与之相当的烃源岩层系发育。     

Depositional model for a prograding oolitic wedge,Upper Jurassic,Iberian basin

Facies architecture and bedding patterns of the Kimmeridgian Pozuel Formation (Iberian Basin) evidence that this 50–70-m thick oolitic-grainstone unit conforms to the Infralittoral Prograding Wedge (ILPW) model instead of the classic models used for interpreting oolitic grainstones sandbodies on carbonate ramps or platforms (i.e., bank-margin shoal complexes, beaches and beach ridges).Ten lithofacies have been distinguished in the Pozuel Formation: 5–10° dipping clinobedded oolitic grainstone foresets passing to tabular oolitic packstones-grainstones, which interfinger the muddy basinal bottomsets. Landwards, the clinobeds pass into subhorizontal topsets composed of trough cross-bedded to structureless oolitic grainstones; oolitic-skeletal grainstones with stromatoporoids and coral-stromatoporoid-microbial mounds. Siliciclastic lithofacies and oncolitic/peloidal packstones occur at the innermost position. These lithofacies stack in strike elongated, 5–20-m thick, 0,5–2 km dip-oriented wide, aggradational-progradational packages with complex sigmoid-oblique geometries.Lithofacies, depositional geometries and stacking pattern permit to summarize the main characteristic of such Upper Jurassic oolitic infralittoral prograding wedge potentially to be applied in other oolitic sandbodies both in outcrops and subsurface: 1) sediment production within the wave action zone, 2) grainstone-dominated textures, 3) prograding basinward onto basinal muds, 4) laterally (strike) extensive, paralleling the shoreline, 5) variable thickness, commonly of few tens of meters, 6) broadly sigmoidal to oblique internal architecture, with topsets, foresets and bottomsets, 7) dip of foresets close to the angle of repose, 8) topsets deposited in shallow-water, extending through the shoreface, from the shoreline down to the wave base, 9) mounds, either microbial or skeletal, may occur in the topsets.The coated-grains factory was along the high-energy, wave-dominated outer platform (topset beds), from where the mud was winnowed and the grains transported both landward to the platform interior, and seaward to the platform edge, from were the grains cascaded down the slopes as grain flows and mass flows, forming clinobeds. This genetic model can be applied to other grain-dominated lithosomes, some of them forming hydrocarbon reservoirs, e.g., the Jurassic Hanifa Formation and some Arab-D (e.g., Qatif Field) in Arabia, the Smackover Formation in northern Louisiana and south Arkansas, the Aptian Shuaiba Formation (e.g., Bu Hasa Field) and the Cenomanian Mishrif Formation (e.g., Umm Adalkh Field) of the Arabian Gulf.     

Triassic to Middle Jurassic stratigraphy of the Kerr McGee 97/12-1 exploration well,offshore southern England

The Triassic through to the Middle Jurassic (Bathonian) stratigraphy of the Kerr McGee 97/12-1 exploration well is described using petrophysical logs, in association with lithological and palaeontological analyses. Over 6210′ of sediment was penetrated, with sixteen Triassic and fourteen Lower–Middle Jurassic sedimentary units recognised, with a total measured depth (T.D) of 7310′ within the Sherwood Sandstone Group, Budleigh Salterton Pebble Beds of Early/Middle Triassic, Olenekian/Anisian age. As expected the sedimentary sequences are comparable to those described from the Wessex Basin, especially the Portland–Wight and Dorset (sub) basins. Of particular note, however, is the very thick halite sequence (1074′) within the Carnian, Dunscombe Mudstone Formation and also an expanded “Paper Shales” (27′) sequence within the earliest Toarcian. A normal fault is noted at 1260′ with the Late Bajocian, Inferior Oolite Group in fault contact with the latest Toarcian, Bridport Sand Formation, Down Cliff Clay Member. The Late Triassic (Rhaetian) to Middle Jurassic (Bathonian) yielded rich microfaunal and palynomorph assemblages, all of which have been previously described throughout northwest Europe. Four microfossils groups (foraminifera, ostracods, dinocysts and miospores) have been used to interpret stratigraphic ages and palaeoenvironments.This study provides new lithological and microfossil data for the Triassic to Middle Jurassic (Bathonian) sequences preserved in the offshore Portland–Wight Basin and provides a key tie-point/reference section for future offshore drilling.     

Provenance of gravity-flow sandstones from the Upper Jurassic–Lower Cretaceous Farsund Formation,Danish Central Graben,North Sea

Through the Upper Jurassic and Lower Cretaceous gravity-flow sandstones were deposited in the Danish Central Graben. These gravity-flow sandstones were deposited within mudstones of the Farsund Formation which is the main source rock in the area, and they are thus potential oil and gas reservoirs. The petrography and geochemistry of the sandstones show good intra well relations and several local geographical relations, which may indicate that they were derived from multiple locally sourced flows and not merely by one basin-axial flow system. The gravity-flow sandstones deposited in the eastern part of the basin are less mature and richer in, especially, carbonates and albite compared to previously deposited Jurassic sandstones and simultaneously deposited sandstones in the western part of the Danish area. This may indicate a division of the basin in an eastern and a western provenance province. This study addresses the provenance of the gravity-flow sandstones by petrographical and geochemical analyses in order to derive possible shared detrital sources as a means of understanding the transport system(s) of the gravity flows.     

地震模型正演在盐下构造中的应用

加蓬盆地是西非海岸盆地之一,自晚侏罗世开始成盆,下白垩统埃詹加组是一套膏盐层,局部发育多个巨厚盐丘,厚度从30～4000m不等。由于盐丘与围岩之间存在很大的速度差异,造成盐下甘巴组目的层地震反射在盐丘部位出现异常。通过地震模型正演技术对盐下地层构造形态进行了分析,研究表明,无论盐丘大小如何,盐丘都会使盐下地层产生“下拉”现象。     

Impacts of stormwater discharges on the nearshore benthic environment of Santa Monica Bay

Although large loads of potentially toxic constituents are discharged from coastal urban watersheds, very little is known about the fates and eventual impacts of these stormwater inputs once they enter the ocean. The goal of this study was to examine the effects of stormwater discharges on the benthic marine environment of Santa Monica Bay. Sediment samples were collected across a gradient of stormwater impact following significantly sized storm events offshore Ballona Creek (a predominantly developed watershed) and Malibu Creek (a predominantly undeveloped watershed). Sediments offshore Malibu Creek had a greater proportion of fine-grained sediments, organic carbon, and naturally occurring metals (i.e., aluminum and iron), whereas sediments offshore Ballona Creek had higher concentrations of anthropogenic metals (i.e., lead) and organic pollutants (i.e., total DDT, total PCB, total PAH). The accumulation of anthropogenic sediment contaminants offshore Ballona Creek was evident up to 2 km downcoast and 4 km upcoast from the creek mouth and sediment concentrations covaried with distance from the discharge. Although changes in sediment texture, organic content, and an increase in sediment contamination were observed, there was little or no alteration to the benthic communities offshore either Ballona or Malibu Creek. Both sites were characterized as having an abundance, species richness, biodiversity and benthic response index similar to shallow water areas distant from creek mouths throughout the Southern California Bight. There was not a preponderance of pollution tolerant, nor a lack or pollution sensitive, species offshore either creek mouth.     

The Valhall Field: a geological overview

The Valhall Field is located within the Central Graben in the southern part of the Norwegian North Sea. The discovery well, 2/8-6, was drilled in 1975 and the field went on production in 1982. Production is currently 55 000 barrels of oil per day. The Valhall Field structure trends NW-SE and has an areal closure in excess of 60 000 acres. The hydrocarbon column measures ～200 m. The structure is located on an elongate anticlinal feature called the Lindesnes Ridge, which developed during Late Cenomanian to Oligocene tectonic movements. The geophysical evaluation of the field is complicated by the existence of a gas-charged Tertiary section which obscures the deeper seismic reflections. Vertical seismic profiles (VSPs) have been utilized in an attempt to resolve the reservoir configuration. Reservoirs occur both in the Tor Formation (Maastrichtian), and in the underlying Hod Formation (Turonian-Coniacian). The Tor Formation is represented by a largely allochthonous chalk facies which thins regionally to the southwest. A crestal graben is developed in which the Tor Formation is locally thick. Autochthonous chalks are characteristic of the Hod Formation. Primary porosity of the chalk varies between 36 to 50% on the crest of structure. Preservation of such high porosity is primarily due to formation overpressure inhibiting mechanical compaction of the chalk. The field contains paraffinic oil of 36 API gravity. It originated from the Upper Jurassic Kimmeridge Clay Formation, which is at peak oil generating capacity under the field at present day.     

Sedimentological analysis and reservoir characterization of a multi-darcy,billion barrel oil field – The Upper Jurassic shallow marine sandstones of the Johan Sverdrup field,North Sea,Norway

The estimated in-place hydrocarbon volume of the giant Johan Sverdrup field is 3.5 billion barrels of oil, the bulk of which is contained in the Upper Jurassic intra-Draupne Formation sandstone. The intra-Draupne Formation sandstone is composed of unusually coarse grained siliciclastic sediments, with an average net/gross of 97% and average porosity of 28%. The median core permeability ranges from 0.5 to 40 Darcies in individual wells, and may reach even higher values based on drill stem testing.The reservoir is interpreted to be a time-transgressive sheet sand, ranging from 2 to 38 m in thickness and covering an area of more than 200 km². Vertical and lateral facies and grain size trends, combined with biostratigraphy and palaeocurrent indicators, are interpreted to demonstrate a westward onlapping, transgressive shoreface depositional system, with local fan delta input.Reservoir properties vary significantly across the field and relative to facies association. In terms of permeability, the upper and lower shoreface associations in the Avaldsnes High area in the east show the highest median values of 25–27 Darcies. The upper and lower shoreface associations in the Augvald Graben area to the west show median values of 15 and 21 Darcies, respectively. The lowest values are observed in the transgressive shoreline, fan delta and spiculitic shoreface associations, i.e. 8 Darcies, 2 Darcies and 0.1 Darcies, respectively. The latter two facies associations are restricted to local areas in the west and northwest.The coarse grain size, lack of fines, scarcity of cementation and extensive sheet-like distribution of siliciclastic sediments make the intra-Draupne Formation sandstone an ideal reservoir. The depositional model presented in this paper may be used as an analogue when exploring for similar, high quality, shallow marine reservoir sands.     

Ferrelo fan, California: Depositional system influenced by Eustatic sea level changes

Remnants of an Eocene fan system are preserved onshore at San Diego and in the central part of the southern California borderland. Even though faults and erosion have truncated its margins, geophysical data and exploratory wells indicate that remaining parts of the fan extend beneath an offshore area nearly 400-km long and 40- to 100-km wide. Environments representing fluvial, fan-delta, shelf-channel, overlapping inner- to outer-fan, and basin-plain facies are recognized or inferred. Three progradational cycles onshore and two distinct pulses of sand accumulation offshore are attributable to eustatic low sea-level stands rather than to tectonic uplift or shifts in depositional patterns. Margin setting represents fan and/or source area