Syntectonic fluid-flow along thrust faults: Example of the South-Pyrenean fold-and-thrust belt

During compressive events, deformation in sedimentary basins is mainly accommodated by thrust faulting and related fold growth. Thrust faults are generally rooted in the basement and may act as conduits or barriers for crustal fluid flow. Most of recent studies suggest that fluid flow through such discontinuities is not apparent and depends on the structural levels of the thrust within the fold-and-thrust belt.In order to constrain the paleofluid flow through the Jaca thrust-sheet-top basin (Paleogene southwest-Pyrenean fold-and-thrust belt) this study compares on different thrust faults located at different structural levels. The microstructures in the different fault zones studied are similar and consist of pervasive cleavage, calcite shear veins (S_V1), extension veins (E_V1) and late dilatation veins (E_V3). In order to constrain the nature and the source of fluids involved in fluid-rock interactions within fault zones, a geochemical approach, based on oxygen and carbon stable isotope and trace element compositions of calcite from different vein generations and host rocks was adopted. The results suggest a high complexity in the paleohydrological behaviors of thrust faults providing evidence for a fluid-flow compartmentalization within the basin. Previous studies in the southern part of the Axial Zone (North of the Jaca basin) indicates a circulation of deep metamorphic water, probably derived from the Paleozoic basement, along fault zones related to the major basement Gavarnie thrust. In contrast, in northern part of the Jaca basin, the Monte Perdido thrust fault is affected by a closed hydrological fluid system involving formation water during its activity. The Jaca and Cotiella thrust faults, in turn, both located more to the south in the basin, are characterized by a composite fluid flow system. Indeed, stable isotope and trace element compositions of the first generations of calcite veins suggest a relatively closed paleohydrological system, whereas the late calcite vein generations, which are probably associated with the late tectonic activity of the basin, support a contribution of both meteoric and marine waters. Based on these results, a schematic fluid-flow model is presented. This model allows visualization of three main fluid flow compartments along a N–S transect.     

Facies recognition of some Tertiary coals applied to prediction of oil source rock occurrence

Coals are oil source rocks in many of the Tertiary basins of Southeast Asia. The precursors of these hydrogen rich and oxygen poor coals are coastal plain peats which have mainly developed in an everwet and tropical climate. In these environments water flow and reworking can concentrate liptinitic kerogen in preference to vitrinitic kerogen. The distribution, petrography and chemistry of the coaly Miocene source rocks present in the Kutai Basin are described. The recognition of environmental controls on the accumulation of potentially oil-prone coals and coaly shales in deltaic environments is an aid to predictive source bed recognition in petroleum exploration. Comments on the environment of deposition of coaly sediments in the basins of the Norwegian Sea are discussed with reference to their possible oil and/or gas sourcing potential. The Triassic - Jurassic coals of the Haltenbanken area may become more oil-prone towards the delta margins, and facies mapping could aid oil exploration in this area.     

Petroleum geochemistry of the Kimmeridge Clay of onshore Southern and Eastern England

The Kimmeridge Clay is considered a major oil source rock for the North Sea hydrocarbon province. The formation is also developed onshore in an organic-rich mudstone facies. This paper examines the possibility of onshore oil generation from the Kimmeridge Clay. Geochemically, onshore basin margin sediments contain rich, potential source horizons with mainly Type l/Type ll oil-prone kerogen, but are immature. Some deeper Cleveland Basin sediments have reached marginal maturity. Burial history reconstruction suggests significant formation palaeoburial depths in central areas of the Cleveland and Wessex Basins. Computed vitrinite isoreflectance contours show the Wealden and Isle of Wight Kimmeridge Clay to be thermally mature. Basin modelling suggests an early Palaeogene onset of oil generation in parts of the Cleveland Basin, while maximum oil generation could have been reached by the formation base in the Isle of Wight area during the late Cretaceous. Although basin subsidence ceased in the Neogene, in the Weald and Isle of Wight, where the formation is still deeply buried, oil generation probably continued for some time during uplift. Thus significant quantities of oil could have been generated. Whether or not this oil is present today however, would depend on the correct timing of suitable migration and trap structures.     

Magmatic Complexes of the Vetlovaya Marginal Sea Paleobasin (Kamchatka): Composition and Geodynamic Setting

This study presents new geochemical and isotope data on igneous rocks of the Vetlovaya marginal sea paleobasin (part of the Late Mesozoic–Cenozoic margin of the northwestern Pacific). The results show that the rock complexes of this marginal sea basin comprise igneous rocks with geochemical compositions similar to those of normal oceanic tholeiites, enriched transitional tholeiites, and ocean island and back-arc basin basalts. Island-arc tholeiitic basalts are present only rarely. The specific geochemical signatures of these rocks are interpreted as being related to mantle heterogeneity and the geodynamic conditions in the basin.     

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.     

Early Carboniferous of the Solway Basin: A tectonostratigraphic model and its bearing on hydrocarbon potential

The Solway Basin forms the western portion of the Northumberland Trough, a Carboniferous basin system trending WSW-ENE across northern England. A study of the tectono-stratigraphic variations along the margins allows certain predictions to be made regarding the hydrocarbon prospectivity of the Dinantian. It is proposed that earliest Carboniferous extension initiated a series of half-grabens separated by transfer zones that have subsequently formed fold culminations and fault belts within the basin. A model for the proposed graben polarity-switching in the basin system is outlined. Differential subsidence across active faults led to pronounced facies variations in the Courcevan-Chadian which subsequently declined in importance until, in Brigantian-Pendleian times, deposition was governed by regional subsidence.The initial stages of graben formation led to the deposition of subaerial coarse clastic facies associations followed by a cyclical series of marine transgressions and regressions. The model anticipates that the best development of reservior facies is in the distal nearshore equivalent of the Early Dinantian alluvial coarse clastics. One of the hydrocarbon objectives identified is stratigraphic trapping in these sands, enhanced by Courceyan-Chadian rollover. Early Carboniferous algal source rocks are considered as lateral equivalents to the reservoirs and are calculated as oil-generating from the Permo-Trias onwards. The Westphalian coals are unlikely to have generated significant gas in the basin.     

Sedimentary facies associations and sequence stratigraphy of source and reservoir rocks of the lacustrine Eocene Niubao Formation (Lunpola Basin,central Tibet)

The Eocene Niubao Formation of the Lunpola Basin, a large Cenozoic intermontane basin in central Tibet, is an important potential hydrocarbon source and reservoir unit. It represents ∼20 Myr of lacustrine sedimentation in a half-graben with a sharply fault-bounded northern margin and a low-angle flexural southern margin, resulting in a highly asymmetric distribution of depositional facies and sediment thicknesses along the N-S axis of the basin. An integrated investigation of well-logs, seismic data, cores and outcrops revealed three third-order sequences (SQ1 to SQ3), each representing a cycle of rising and falling lake levels yielding lowstand, transgressive, and highstand systems tracts. Lowstand systems tracts (LST) include delta and fan delta facies spread widely along the gentle southern margin and concentrated narrowly along the steep northern margin of the basin, with sublacustrine fan sand bodies extending into the basin center. Highstand systems tracts (HST) include expanded areas of basin-center shale deposition, with sublacustrine fans, deltas and fan deltas locally developed along the basin margins. Sequence development may reflect episodes of tectonic uplift and base-level changes. The southern margin of the basin exhibits two different structural styles that locally influenced sequence development, i.e., a multi-step fault belt in the south-central sector and a flexure belt in the southeastern sector. The sedimentary model and sequence stratigraphic framework developed in this study demonstrate that N2 (the middle member of Niubao Formation) exhibits superior hydrocarbon potential, characterized by thicker source rocks and a wider distribution of sand-body reservoirs, although N3 (the upper member of Niubao Formation) also has good potential. Fault-controlled lithologic traps are plentiful along the basin margins, representing attractive targets for future exploratory drilling for hydrocarbons.     

The gradual subduction-collision evolution model of Proto-South China Sea and its control on oil and gas

This study involved outcrop, drilling, seismic, gravity, and magnetic data to systematically document the geological records of the subduction process of Proto-South China Sea (PSCS) and establish its evolution model. The results indicate that a series of arc-shaped ophiolite belts and calcalkaline magmatic rocks are developed in northern Borneo, both of which have the characteristics of gradually changing younger from west to east, and are direct signs of subduction and collision of PSCS. At the same time, the subduction of PSCS led to the formation of three accretion zones from the south to the north in Borneo, the Kuching belt, Sibu belt, and Miri belt. The sedimentary formation of northern Borneo is characterized by a three-layer structure, with the oceanic basement at the bottom, overlying the deep-sea flysch deposits of the Rajang–Crocker group, and the molasse sedimentary sequence that is dominated by river-delta and shallow marine facies at the top, recording the whole subduction–collision–orogeny process of PSCS. Further, seismic reflection and tomography also confirmed the subduction and collision of PSCS. Based on the geological records of the subduction and collision of PSCS, combined with the comprehensive analysis of segmented expansion and key tectonic events in the South China Sea, we establish the “gradual” subduction-collision evolution model of PSCS. During the late Eocene to middle Miocene, the Zengmu, Nansha, and Liyue–Palawan blocks were separated by West Baram Line and Balabac Fault, which collided with the Borneo block and Kagayan Ridge successively from the west to the east, forming several foreland basin systems, and PSCS subducted and closed from the west to the east. The subduction and extinction of PSCS controlled the oil and gas distribution pattern of southern South China Sea (SSCS) mainly in three aspects. First, the “gradual” closure process of PSCS led to the continuous development of many large deltas in SSCS. Second, the deltas formed during the subduction–collision of PSCS controlled the development of source rocks in the basins of SSCS. Macroscopically, the distribution and scale of deltas controlled the distribution and scale of source rocks, forming two types of source rocks, namely, coal measures and terrestrial marine facies. Microscopically, the difference of terrestrial higher plants carried by the delta controlled the proportion of macerals of source rocks. Third, the difference of source rocks mainly controlled the distribution pattern of oil and gas in SSCS. Meanwhile, the difference in the scale of source rocks mainly controlled the difference in the amount of oil and gas discoveries, resulting in a huge amount of oil and gas discoveries in the basin of SSCS. Meanwhile, the difference of macerals of source rocks mainly controlled the difference of oil and gas generation, forming the oil and gas distribution pattern of “nearshore oil and far-shore gas”.     

南黄海盆地北部坳陷北凹油气成藏特征的再认识

南黄海盆地北部坳陷北凹是一个大中型的中、新生代沉积凹陷,经过四十余年的油气勘探,至今仍无商业油气发现,仅发现诸城1-2一个含油气构造.北凹的油气勘探存在诸多问题,其中是否发育优质烃源岩、烃源岩能否生烃、油气是否运移至储层是关系到北凹油气勘探的基础地质问题.在对北凹主要烃源岩分析评价的基础上,采用流体包裹体系统分析技术,对北凹油气成藏特征展开研究.研究认为,北凹存在白垩系泰二段主力烃源岩,为中深湖相,生烃指标较好,分布面积较大,且现今已经成熟并排烃,生烃中心位于ZC-A井区.油气通过断裂发生垂向运移,已充注至始新统戴南组储层.流体包裹体荧光观察结果及显微测温结果均表明戴南组至少存在两期油充注,第一期发生在35 Ma左右,第二期为现今.     

Evaluation method and application of the relative contribution of marine hydrocarbon source rocks in the Tarim basin: A case study from the Tazhong area

In total, 2.37 million tons of marine crude oil originating from mixed source rocks has been discovered in the Tarim basin. Geological and geochemical analyses have confirmed that these mixed hydrocarbons are mainly from two sets of source rocks, including the Cambrian – Lower Ordovician and Middle-Upper Ordovician hydrocarbon source rocks. In this study, we determined the set of source rocks primarily responsible for the mixed hydrocarbons and the next location to be explored. Differences in n-alkane carbon isotopes in end-member oils from Cambrian–Lower Ordovician and Middle-Upper Ordovician source rocks were examined. A material balance model and simulation methods were used to evaluate the relative amounts contributed by each source. The results from known reserves in the Tazhong area show that the mixing ratio or contribution is up to 65% from Cambrian–Lower Ordovician source rocks and is generally higher than that from Middle-Upper Ordovician source rocks. The discovery of deep hydrocarbons has caused the total oil contribution from the Cambrian–Lower Ordovician to increase. The mixing ratio of Cambrian–Lower Ordovician oil varies depending on the well, formation, and block. It increases from west to east horizontally and from top to bottom vertically. Hydrocarbons from Cambrian–Lower Ordovician source rocks migrate upward along faults, and the mixing ratio decreases as the distance from the oil source fault increases. Favorable areas for Cambrian–Lower Ordovician hydrocarbon exploration are deep layers and areas near the fault zone that are connected to deep layers. The material balance model for carbon isotopes and evaluation methods for relative contributions considered differences in relative concentration and carbon isotope structure of n-alkanes. Herein, new methods for the identification and evaluation of hydrocarbons in the petroleum system of this superimposed basin are presented.     

Oil/gas–source rock correlations in the Dniepr-Donets Basin (Ukraine): New insights into the petroleum system

The Dniepr-Donets Basin (DDB) hosts a multi-source petroleum system with more than 200 oil and gas fields, mainly in Carboniferous clastic rocks. Main aim of the present study was to correlate accumulated hydrocarbons with the most important source rocks and to verify their potential to generate oil and gas. Therefore, molecular and isotopic composition as well as biomarker data obtained from 12 oil and condensate samples and 48 source rock extracts was used together with USGS data for a geological interpretation of hydrocarbon charging history.Within the central DDB, results point to a significant contribution from (Upper) Visean black shales, highly oil-prone as well as mixed oil- and gas-prone Serpukhovian rocks and minor contribution from an additional Tournaisian source. Devonian rocks, an important hydrocarbon source within the Pripyat Trough, have not been identified as a major source within the central DDB. Additional input from Bashkirian to Moscovian (?) (Shebelinka Field) as well as Tournaisian to Lower Visean rocks (e.g. Dovgal Field) with higher contents of terrestrial organic matter is indicated in the SE and NW part, respectively.Whereas oil–source correlation contradicts major hydrocarbon migration in many cases for Tournaisian to Middle Carboniferous reservoir horizons, accumulations within Upper Carboniferous to Permian reservoirs require vertical migration up to 4000 m along faults related to Devonian salt domes.1-D thermal models indicate hydrocarbon generation during Permo-Carboniferous time. However, generation in coal-bearing Middle Carboniferous horizons in the SE part of the basin may have occurred during the Mesozoic.     

Impact of high water pressure on oil generation and maturation in Kimmeridge Clay and Monterey source rocks: Implications for petroleum retention and gas generation in shale gas systems

This study presents results for pyrolysis experiments conducted on immature Type II and IIs source rocks (Kimmeridge Clay, Dorset UK, and Monterey shale, California, USA respectively) to investigate the impact of high water pressure on source rock maturation and petroleum (oil and gas) generation. Using a 25 ml Hastalloy vessel, the source rocks were pyrolysed at low (180 and 245 bar) and high (500, 700 and 900 bar) water pressure hydrous conditions at 350 °C and 380 °C for between 6 and 24 h. For the Kimmeridge Clay (KCF) at 350 °C, Rock Eval HI of the pyrolysed rock residues were 30–44 mg/g higher between 6 h and 12 h at 900 bar than at 180 bar. Also at 350 °C for 24 h the gas, expelled oil, and vitrinite reflectance (VR) were all reduced by 46%, 61%, and 0.25% Ro respectively at 900 bar compared with 180 bar. At 380 °C the retardation effect of pressure on the KCF was less significant for gas generation. However, oil yield and VR were reduced by 47% and 0.3% Ro respectively, and Rock Eval HI was also higher by 28 mg/g at 900 bar compared with 245 bar at 12 h. The huge decrease in gas and oil yields and the VR observed with an increase in water pressure at 350 °C for 24 h and 380 °C for 12 h (maximum oil generation) were also observed for all other times and temperatures investigated for the KCF and the Monterey shale. This shows that high water pressure significantly retards petroleum generation and source rock maturation. The retardation of oil generation and expulsion resulted in significant amounts of bitumen and oil being retained in the rocks pyrolysed at high pressures, suggesting that pressure is a possible mechanism for retaining petroleum (bitumen and oil) in source rocks. This retention of petroleum within the rock provides a mechanism for oil-prone source rocks to become potential shale gas reservoirs. The implications from this study are that in geological basins, pressure, temperature and time will all exert significant control on the extent of petroleum generation and source rock maturation for Type II source rocks, and that the petroleum retained in the rocks at high pressures may explain in part why oil-prone source rocks contain the most prolific shale gas resources.     

Volcanism and Tectonics of the Central Deep Basin,Sea of Japan

The paper presents the results of a study on the geomorphic structure, tectonic setting, and volcanism of the volcanoes and volcanic ridges in the deep Central Basin of the Sea of Japan. The ridges rise 500–600 m above the acoustic basement of the basin. These ridges were formed on fragments of thinned continental crust along deep faults submeridionally crossing the Central Basin and the adjacent continental part of the Primorye. The morphostructures of the basin began to submerge below sea level in the Middle Miocene and reached their contemporary positions in the Pliocene. Volcanism in the Central Basin occurred mostly in the Middle Miocene–Pliocene and formed marginal-sea basaltoids with OIB (ocean island basalt) geochemical signatures indicating the lower-mantle plume origin of these rocks. The OIB signatures of basaltoids tend to be expressed better in the eastern part of the Central Basin, where juvenile oceanic crust has developed. The genesis of this crust is probably related to rising and melting of the Pacific superplume apophyse.     

冲绳海槽南段基底组成探讨

本文根据反射地震、折射地震、磁力等资料,结合周边地质,探讨冲绳海槽南段基底组成。在海槽周边的东海陆架盆地、台湾褶皱带和琉球岛弧褶皱带,均出露不同程度变质的晚古生代、中生代和早第三纪地层。多道反射地震表明,海槽南段沉积盖层由上第三系和第四系组成,声学基底由下第三系及更老地层构成。邻近海槽的折射地震揭示,除第四系-中新统速度层之外,还存在纵波速度分别为4．7～5．3km／s和6．3km／s的下第三系和中生界速度层。磁异常分析和正反演拟合计算结果表明,海槽磁性基底主要由变质岩系构成,次为燕山期中酸性岩浆岩和喜山期中基性岩浆岩,磁性基底大部分相当声学基底。综合分析表明,海槽南段基底主要由不同程度变质的下第三系、中生界和上古生界构成;在海槽某些构造部位,已有喜山期基性岩浆岩形成。     

Black shales in Ukraine – A review

As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing.     

Establishing hydrocarbon charge to the Ashmore Platform,Bonaparte Basin,Australia: A natural seeps study

To date there is one proven hydrocarbon accumulation on the Ashmore Platform, Bonaparte Basin, Australia, with hydrocarbon charge remaining a key exploration risk. To the south, the neighbouring Browse Basin has proven lateral migration of generated hydrocarbons to the basin bounding highs, as evidenced by seeps located on the Yampi Shelf. This paper describes the findings of a natural seeps study carried out to establish if migrating subsurface hydrocarbons reach the southern flanks of the Ashmore Platform basement high. The integrated study combined remote sensing, geophysical, acoustic, photographic and geochemical techniques and has identified three areas of seepage; one area characteristic of persistent seepage and two areas of interpreted episodic leakage. Geochemical data collected from samples at one of these sites demonstrates the presence of thermogenic liquid hydrocarbons, with isotopic compositions falling within the range of values exhibited by oils sourced by the Lower Cretaceous Echuca Shoals Formation. The identification of active natural seepage along the southern flank of the Ashmore Platform provides evidence that hydrocarbons generated within the Caswell Sub-basin are able to laterally migrate onto the flanks of the Ashmore Platform structural high. As such, these findings reduce charge risk for the Ashmore Platform and regional exploration risks in the northern Browse Basin.     

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.     

Geochemical characterization of oils and their correlation with Jurassic source rocks from the Lusitanian Basin (Portugal)

Seeking to identify the oils groups accumulated in the Jurassic of the Lusitanian Basin and the source rock of each group, stable carbon isotope and gas chromatography coupled with mass spectrometry analyses were performed in oils and oil shows from the main discoveries, and on representative organic extracts from the potential source rocks, selected based on previous works and data obtained by total organic carbon and Rock-Eval pyrolysis techniques. The geochemical comparison between the oils, and between the oils and the organic extracts, allowed the identification of three oil groups, whose differences depend on their source rocks: oils generated at the Coimbra Formation (lower-upper Sinemurian) and accumulated in the same formation and in the Água de Madeiros Formation (upper Sinemurian-lower Pliensbachian) in the northern sector of the basin; oils originated from the top of the Cabaços Formation (middle Oxfordian) and accumulated in the Montejunto (middle-upper Oxfordian) and Abadia (lower-upper Kimmeridgian) formations, in the central and southern sectors of the basin; and oil generated and accumulated at the base of the Montejunto Formation in the central sector of the basin. The geochemical correlations between the oils and the organic extracts allowed the identification of the source rocks of the different accumulations of the Jurassic succession, allowing further guidance to the petroleum exploration in the Lusitanian Basin.     

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.     

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin,eastern Yemen

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S₁ + S₂) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.