Basin modeling of the Late Miocene Zeit source rock in the Sudanese portion of Red Sea Basin: Implication for hydrocarbon generation and expulsion history

The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m². The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source.The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m², increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene.The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin.     

Hydrocarbon source rock potential in the southwestern Gulf of Suez graben: Insights from organic geochemistry and palynofacies studies on well samples from the Ras El Bahar Oilfield

Palynological and biomarker characteristics of organic facies recovered from Cretaceous–Miocene well samples in the Ras El Bahar Oilfield, southwest Gulf of Suez, and their correlation with lithologies, environments of deposition and thermal maturity have provided a sound basis for determining their source potential for hydrocarbons. In addition to palynofacies analysis, TOC/Rock-Eval pyrolysis, kerogen concentrates, bitumen extraction, carbon isotopes and saturated and aromatic biomarkers enable qualitative and quantitative assessments of sedimentary organic matter to be made. The results obtained from Rock-Eval pyrolysis and molecular biomarker data indicate that most of the samples come from horizons that have fair to good hydrocarbon generation potential in the study area. The Upper Cretaceous–Paleocene-Lower Eocene samples contain mostly Type-II to Type-III organic matter with the capability of generating oil and gas. The sediments concerned accumulated in dysoxic–anoxic marine environments. By contrast, the Miocene rocks yielded mainly Type-III and Type-II/III organic matter with mainly gas-generating potential. These rocks reflect deposition in a marine environment into which there was significant terrigenous input. Three palynofacies types have been recognized. The first (A) consists of Type-III gas-prone kerogen and is typical of the Early–Middle Miocene Belayim, Kareem and upper Rudeis formations. The second (B) has mixed oil and gas features and characterizes the remainder of the Rudeis Formation. The third association (C) is dominated by amorphous organic matter, classified as borderline Type-II oil-prone kerogen, and is typical of the Matulla (Turonian–Santonian) and Wata (Turonian) formations. Rock-Eval T_max, PI, hopane and sterane biomarkers consistently indicate an immature to early mature stage of thermal maturity for the whole of the studied succession.     

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

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

Source rocks and petroleum systems in the Hungarian part of the Pannonian Basin: The potential for shale gas and shale oil plays

The objectives of our study were to assess the thickness, lateral extent, organic richness and maturity of the potential source rocks in Hungary and to estimate the volumes of hydrocarbons generated, in order that potential shale gas and shale oil plays could be identified and characterised.The Upper Triassic Kössen Marl in south-west Hungary could represent the best potential shale gas/shale oil play, due to its high organic richness, high maturity and the presence of fracture barriers. The area of gas- and oil-generative maturity is around 720 km² with the unexpelled petroleum estimated to be up to 9 billion barrel oil-equivalent.The Lower Jurassic sediments of the Mecsek Mountains and under the Great Plain contain fair quality gas-prone source rocks, with low shale gas potential, except for a thin Toarcian shale unit which is richer in organic matter. The latter could form a potential shale gas play under the Great Hungarian Plain, if it is thicker locally.The Lower Oligocene Tard Clay in north-east Hungary could represent the second best potential shale oil play, due to its organic richness, favourable maturity and large areal extent (4500 km²) with around 7 billion barrel oil-equivalent estimated in-place volume of petroleum.Middle Miocene marine formations could represent locally-developed shale gas plays; they have fair amounts of organic matter and a mixture of type II/III kerogen, but their vertical and lateral variability is high.The Upper Miocene lacustrine Endrőd Marl contains less organic matter and the kerogen is mainly type III, which is not favourable for shale gas generation. The high carbonate and clay content, plus the lack of upper and lower fracture barriers would represent additional production challenges.     

Siliciclastic influx and burial of the Cenozoic carbonate system in the Gulf of Papua

An extensive carbonate system in the Gulf of Papua (GoP), developed in the late Oligocene–middle Miocene, was buried by huge influx of siliciclastics originated from Papua New Guinea. Major episodes of siliciclastic influx in the carbonate system are related to tectonic activity in the fold and thrust belt during the Oligocene Peninsular Orogeny, late Miocene Central Range Orogeny, and late Pliocene renewed uplift and exhumation of peninsular region. Siliciclastics did not influence the carbonate deposition during the late Oligocene–middle Miocene, since they were accumulated in the Aure Trough, proximal foreland basin protecting the carbonate system. The most significant burial of the carbonate system started during the late Miocene–early Pliocene in the result of the Central Range Orogeny. However, the largest influx was related to the renewed uplift of the Papuan Peninsula during the early late Pliocene. The shelf edge prograded ∼150 km and formed more than 80% of the modern shelf. This high siliciclastic influx was also enhanced by the “mid” Pliocene global warmth period and intensified East Asian monsoons at 3.6–2.9 Ma. Although many publications exist on carbonate–siliciclastic mixing in different depositional environments, this study helps understand the carbonate–siliciclastic interactions in space and time, especially at basinal scale, and during different intervals of the carbonate system burial by siliciclastic sediments.     

Thermal evolution of the Kuh-e-Asmari and Sim anticlines in the Zagros fold-and-thrust belt: Implications for hydrocarbon generation

Mixed layer clay minerals, vitrinite reflectance and geochemical data from Rock-Eval pyrolysis were used to constrain the burial evolution of the Mesozoic–Cenozoic successions exposed at the Kuh-e-Asmari (Dezful Embayment) and Sim anticlines (Fars province) in the Zagros fold-and-thrust belt. In both areas, Late Cretaceous to Pliocene rocks, show low levels of thermal maturity in the immature stages of hydrocarbon generation and early diagenetic conditions (R0 I–S and R_o% values < 0.5). At depths of 2–4 km, T_max values (435–450 °C) from organic-rich layers of the Sargelu, Garau and Kazhdumi source rocks in the Kuh-e-Asmari anticline indicate mid to late mature stages of hydrocarbon generation. One dimensional thermal models allowed us to define the onset of oil generation for the Middle Jurassic to Eocene source rocks and pointed out that sedimentary burial is the main factor responsible for measured levels of thermal maturity. Specifically, the Sargelu and Garau Formations entered the oil window prior to Zagros folding in Late Cretaceous times, the Kazhdumi Formation during middle Miocene (syn-folding stage), and the Pabdeh Formation in the Late Miocene–Pliocene after the Zagros folding. In the end, the present-day distribution of oil fields in the Dezful Embayment and gas fields in the Fars region is primarily controlled by lithofacies changes and organic matter preservation at the time of source rock sedimentation. Burial conditions during Zagros folding had minor to negligible influence.     

Fluxes of amino acids and hexosamines to the deep Arabian Sea

Results of organic carbon, total nitrogen, amino acid and hexosamine analyses of samples collected during time-series sediment trap investigations in the Arabian Sea are presented. Samples were taken over a period of years at two depths at each of three locations in the western, central and eastern part of the basin. Seasonal changes in amino acid contents and their spectral distributions show that degradation of organic matter in the water column is reduced during the monsoons, which are the high-flux periods in the western and central Arabian Sea. At the eastern site more degraded material of possibly recycled marine or terrestrial origin reaches the traps during the late summer peak fluxes. The results of hexosamine analyses suggest that bacterial biomass is relatively enriched on particles sinking in the water column and, to a larger extent, at the sediment-water interface. Decomposition between intermediate and deep water results in a loss of 30–40% of total organic carbon and more than 40% of amino acids. Comparison of the measured accumulation rates of organic carbon in sediment traps with those of organic carbon preserved in sediments show that more than 85% is lost before final burial in the sediments. Organic matter preservation in the Arabian Sea is higher than the average for the open ocean; this maybe due to the abundance of refractory organic matter of recycled marine or terrestrial origin.     

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.     

Insights into deposition of Lower Cretaceous black shales from meager accumulation of organic matter in Albian sediments from ODP site 763, Exmouth Plateau,Northwest Australia

The amount and type of organic matter present in an exceptionally complete upper Aptian to lower Cenomanian sequence of sediments from ODP site 763 on the Exmouth Plateau has been determined. Organic carbon concentrations average 0.2%. Organic matter is marine in origin, and its production and preservation was low over the ca. 20-million-year interval recorded by this sequence. Because this section was tectonically isolated from mainland Australia in the early Aptian, it better represents global oceanic conditions than the many basin-edge locations in which Albian-age black shales have been found. Formation of the basin-edge black shales evidently resulted from rapid, turbiditic burial of organic matter rather than from enhanced oceanic production or from basin-wide anoxia during the Albian.     

Organic geochemistry and petroleum potential of Early Cretaceous Garau Formation in central part of Lurestan zone,northwest of Zagros,Iran

Deposition of organic rich black shales and dark gray limestones in the Berriasian-Turonian interval has been documented in many parts of the world. The Early Cretaceous Garau Formation is well exposed in Lurestan zone in Iran and is composed of organic-rich shales and argillaceous limestones. The present study focuses on organic matter characterization and source rock potential of the Garau Formations in central part of Lurestan zone. A total of 81 core samples from 12 exploratory wells were subjected to detailed geochemical analyses. These samples have been investigated to determine the type and origin of the organic matter as well as their petroleum-generation potential by using Rock-Eval/TOC pyrolysis, GC and GCMS techniques. The results showed that TOC content ranges from 0.5 to 4.95 percent, PI and Tmax values are in the range of 0.2 and 0.6, and 437 and 502 °C. Most organic matter is marine in origin with sub ordinary amounts of terrestrial input suggesting kerogen types II-III and III. Measured vitrinite reflectance (Rrandom%) values varying between 0.78 and 1.21% indicating that the Garau sediments are thermally mature and represent peak to late stage of hydrocarbon generation window. Hydrocarbon potentiality of this formation is assessed fair to very good capable of generating chiefly gas and some oil. Biomarker characteristics are used to provide information about source and maturity of organic matter input and depositional environment. The relevant data include normal alkane and acyclic isoprenoids, distribution of the terpane and sterane aliphatic biomarkers. The Garau Formation is characterized by low Pr/Ph ratio (<1.0), high concentrations of C27 regular steranes and the presence of tricyclic terpanes. These data indicated a carbonate/shale source rock containing a mixture of aquatic (algal and bacterial) organic matter with a minor terrigenous organic matter contribution that was deposited in a marine environment under reducing conditions. The results obtained from biomarker characteristics also suggest that the Garau Formation is thermally mature which is in agreement with the results of Rock-Eval pyrolysis.     

Depositional environment of oil shale within the Eocene Jijuntun Formation in the Fushun Basin (NE China)

The non-marine Fushun Basin in NE China is a fault-controlled basin filled with Eocene sediments. It hosts the largest opencast coal and oil shale mine in Asia. A single thick oil shale layer overlying sub-bituminous coal occurs within the Middle Eocene Jijuntun Formation. Based on mineralogy, inorganic and organic geochemistry, organic petrography, stable isotope geochemistry, and vitrinite reflectance measurements, the depositional environment and the oil shale potential of the oil shale-bearing succession were investigated. The Jijuntun Formation is subdivided into a lower and an upper unit characterized by a low and high quality oil shale, respectively. The thick oil shale layer of the Jijuntun Formation developed under long-lasting stable conditions in a deep freshwater lake, after drowning of a swamp. The organic matter in the lower unit is characterized by landplant-derived macerals. The sediments containing a type II kerogen (HI: ∼400 mgHC/gTOC) were deposited during warm and humid conditions. Lacustrine organisms predominant in the upper unit are forming kerogen type I (HI: ∼700 mgHC/gTOC). High bioproductivity and excellent preservation conditions resulted in high TOC contents up to 23.6 wt.% in the upper unit. The organic matter preservation was controlled by photic zone anoxia originating in a temperature stratified water column in the deep lake, without significant changes in bottom water salinity. Mid-Eocene cooling during deposition of the upper unit of the Jijuntun Formation is reflected by clay mineral composition. A hot and arid climate favoring brackish conditions in a shallow lake prevailed during accumulation of the overlying carbonate-rich Xilutian Formation. Individual geochemical parameters in the Fushun Basin have to be used with caution, e.g. the maturity proxy T_max is affected by kerogen type, the redox proxy Pr/Ph ratio is probably biased by different sources of isoprenoids. This demonstrates the importance of multi-proxy studies.     

Biomarkers reveal the terrigenous organic matter enrichment in the late Oligocene-early Miocene marine shales in the Ying-Qiong Basin,South China Sea

The increase of total organic carbon content of the late Oligocene-early Miocene terrigenously-dominated marine shales in the shallower depth intervals was reported in the Ying-Qiong Basin, South China Sea. The organic enriched lower Sanya Formation shales(early Miocene) have biomarker characteristics of tropical/subtropical plants, with abundant high molecular weight n-alkanes, angiosperm-derived oleanane,rearranged oleananes Ⅰ, Ⅱ, Ⅱ, tricyclic/tetracyclic terpanes including des-A-oleanane, X, ...     

Organic matter source and thermal maturity within the Late Cretaceous Niobrara Formation,U.S. Western Interior

The Late Cretaceous sedimentary record of the North American Western Interior Seaway is characterized by cyclic deposition of organic carbon-rich sediments. One notable interval during the late Coniacian-Santonian is recorded by the Niobrara Formation. The organic carbon-rich interval within the Niobrara Formation has been identified as Oceanic Anoxic Event (OAE) 3. Understanding the reason for this distribution of organic carbon within the Niobrara Formation requires a refined understanding of the source and maturity of the organic matter. In this study, we present lipid biomarker records from the USGS Portland #1 core (Cañon City, CO) to constrain the thermal maturity of the organic matter and the differing contributions of organic matter sources. Sterane and hopane thermal maturity indices indicate that the samples are somewhat immature with respect to oil formation and that there is strong agreement between different proxies for thermal maturity. Based on the distribution of n-alkanes, steranes, and hopanes, there is a significant increase in the contribution of algal organic matter during and after OAE 3, coeval with increased organic carbon accumulation. Although a consistent terrestrial contribution is observed, it is only a minor source of organic matter at the Portland core location and does not drive increased organic matter accumulation during OAE 3. Of particular note is the consistent influence of even-over-odd predominantly mid-chain length (C₂₁ to C₂₅) organic matter. This observation within the brackish to marine, not methanogenic WIS represents an expansion of the depositional settings in which even-over-odd predominance has been observed in mid-chain length n-alkanes. Pristane (Pr) and phytane (Ph) abundances are inconsistent with a redox control on Pr/Ph ratios and suggest an increase in the delivery and/or preservation of phototrophic organic matter as the source for pristane and phytane in the Portland core.     

Hydrocarbon source potential of Eocene-Miocene sequence of Western Sabah,Malaysia

An evaluation of the petroleum generating potential of onshore Eocene-Miocene sequences of Western Sabah, Malaysia was performed based on organic petrological and geochemical methods. The sequences analysed are the Belait, Meligan, Temburong and West Crocker formations of western Sabah. The Belait Formation which is Stage IV equivalent in the offshore represents one of the major source rock/reservoirs of the petroleum-bearing Sabah Basin. The Eocene-Early Miocene West Crocker and Temburong formations are deepwater turbidites whilst the Miocene Meligan and Belait formations are shallow marine fluvio-deltaic deposits. The vitrinite reflectance and pyrolysis T_max values show that the Belait samples are generally immature for hydrocarbon generation, whereas the Meligan, Temburong and West Crocker samples are in the mature to late maturity stage of hydrocarbon generation. The overall bulk source rock properties of the Belait and Meligan show fair to good petroleum source rock potential with TOC more than 1 wt %, hydrocarbon yield in the range of 400–1300 ppm and moderately high HI for many of the samples. Most of the samples representing the Temburong and West Crocker formations have TOC less than 1 wt% and have no to fair hydrocarbon generating potential. Interestingly, the samples collected in the West Crocker Formation characterized by slump deposits (MTD) have TOC>2 and possess good to excellent hydrocarbon generating potential. The organic matter present in all of the studied formations is mainly of terrigenous origin based on the abundance of woody plant materials observed under the microscope. Consequently, the analysed sequences are predominantly gas prone, dominated by Type III and Type III-IV kerogen except for minor occurrence of mixed oil-gas prone Type II-III kerogen in the Belait Formation and in the slump mass transport deposits (MTD) of the West Crocker Formation.     

New perspective of Miocene marine hydrocarbon source rocks in deep-water area in Qiongdongnan Basin of northern South China Sea

Drilling wells reveal that the organic matter abundance of Miocene marine source rocks in shallow water area of the Qiongdongnan Basin is relatively low with poor hydrocarbon generation poten- tial. However, in some drilling wells of deep water area close to the central depression belt, Miocene marine source rocks with better organic matter abundance and hydrocarbon generation have been found, which have achieved better source rock standard based on the analysis of geochemical charac- teristics. Although there are no exploratory wells in deep water area of the research region, through the comparative analysis of geochemical data of several typical exploratory wells respectively from shallow water area in the basin, central depression belt margin in deep-water area of the basin and Site 1148 of deep sea drilling in the South China Sea Basin, it reveals that the tendency of the quality of source rocks becomes positive gradually from delta to bathyal environment, which then becomes negative as in deep oceanic environment. Owing to the lack of terrestrial organic matter input, the important controlling factors of Miocene marine source rocks in the Qiongdongnan Basin are ocean productivity and preservation conditions of organic matter. The element geochemistry data indicate that the tendency of the paleoproductivity and the preservation conditions of organic matter become positive as water depth increase from shallow area to bathyal area close to central depression belt. So it is speculated that there must exist high quality source rocks in the central depression area where the preservation conditions of organic matter are much better. Besides, in theory, in oxygen-poor zone of oceanic environment at the water depth 400-1 000 m, the preservation conditions of organic matter are well thus forming high-quality marine source rocks. The result- ing speculation, it is reasonable to consider that there are high hydrocarbon generation potential source rocks in bathyal environment of the Qiongdongnan Basin, especially at the water depth 400- 1 000 m.     

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.     

Middle to Late Cenozoic tectonic events in south and central Palawan (Philippines) and their implications to the evolution of the south-eastern margin of South China Sea: Evidence from onshore structural and offshore seismic data

Using recently gathered onland structural and 2D/3D offshore seismic data in south and central Palawan (Philippines), this paper presents a new perspective in unraveling the Cenozoic tectonic history of the southeastern margin of the South China Sea. South and central Palawan are dominated by Mesozoic ophiolites (Palawan Ophiolite), distinct from the primarily continental composition of the north. These ophiolites are emplaced over syn-rift Eocene turbidites (Panas Formation) along thrust structures best preserved in the ophiolite–turbidite contact as well as within the ophiolites. Thrusting is sealed by Early Miocene (∼20 Ma) sediments of the Pagasa Formation (Isugod Formation onland), constraining the younger limit of ophiolite emplacement at end Late Oligocene (∼23 Ma). The onset of ophiolite emplacement at end Eocene is constrained by thrust-related metamorphism of the Eocene turbidites, and post-emplacement underthrusting of Late Oligocene – Early Miocene Nido Limestone. This carbonate underthrusting at end Early Miocene (∼16 Ma) is marked by the deformation of a seismic unit corresponding to the earliest members of the Early – Middle Miocene Pagasa Formation. Within this formation, a tectonic wedge was built within Middle Miocene (from ∼16 Ma to ∼12 Ma), forming a thrust-fold belt called the Pagasa Wedge. Wedge deformation is truncated by the regionally-observed Middle Miocene Unconformity (MMU ∼12 Ma). A localized, post-kinematic extension affects thrust-fold structures, the MMU, and Late Miocene to Early Pliocene carbonates (e.g. Tabon Limestone). This structural set-up suggests a continuous convergent regime affecting the southeastern margin of the South China Sea between end Eocene to end Middle Miocene. The ensuing structures including juxtaposed carbonates, turbidites and shallow marine clastics within thrust-fold belts have become ideal environments for hydrocarbon generation and accumulation. Best developed in the Northwest Borneo Trough area, the intensity of thrust-fold deformation decreases towards the northeast into offshore southwest Palawan.     

民和盆地侏罗系生烃潜力与油气勘探方向

从有机碳含量、可溶有机质含量及其转化率、热解参数、饱和烃的生物表示化合物特征、有机岩石学特征几个方面分析了民和盆地侏罗系烃源岩的有机质丰度、类型和成熟度,并进行了地球化学特征分析和生烃潜力评价。分析认为盆地发育湖相泥岩和煤系两大类烃源岩,有机质以较富含低等水生生物原始母质的腐泥腐殖型为主,主要分布于中侏罗统。通过对盆地石油地质条件的评价,结合各区带落实认识程度和资料品质条件认为：武家鼻隆构造带是最有利的勘探区带,万泉堡鼻状构造带具有良好勘探潜力,大庄构造带是寻找浅层次生油气藏的有利区带。永登凹陷面积大,资源丰富,勘探认识程度低,具有良好勘探前景。     

Basin scale distribution of organic matter in marine fine-grained sedimentary rocks: Insight from sequence stratigraphy and multi-proxies analysis in the Montney and Doig Formations

The occurrence of hydrocarbons in self-sourced reservoirs strongly depends on the concentration and maturity of organic matter in sediments. Therefore, understanding the distribution of organic heterogeneity at the time of deposition is key to reduce the risk in exploration and development of unconventional resources. This study focuses on the Lower and Middle Triassic Montney and Doig Formations (Alberta and British Columbia). Samples from outcrops, cores and cuttings were analyzed for organic content with a Rock-Eval VI and for major and trace element concentration using ICP-MS and ICP-AES techniques. The interpretation of the analysis results in relation with the stratigraphic architecture provides a mean to better understand the distribution of the organic heterogeneities and the variations of primary productivity, sedimentation rates and anoxia that control the development of source rocks.The key findings of this analysis are:- The basin-scale distribution of the organic matter suggests that the two major source-rock intervals of the Lower and Middle Triassic correspond to the sequence 3 (Spathian Montney unit) and to the transgressive systems tract of sequence 4 (Doig phosphate zone).- The dominant controls on organic matter accumulations vary through time. The Montney source-rock interval is interpreted to be associated with a major basin restriction triggering anoxia during a second-order falling stage of relative sea level. The organic accumulation of the Doig phosphate zone is interpreted as being controlled by a sharp decrease of the sedimentation rate, combined with an increase of the primary productivity.- The spatial and temporal variations of anoxia, primary productivity and dilution reflect the geodynamic evolution of the basin that ultimately controls the basin physiography as well as the sources of nutrient and sediments.     

Organic geochemistry and source potential of the lacustrine shales of the Upper Triassic - Lower Jurassic Kap Stewart Formation, East Greenland

The Upper Triassic — Lower Jurassic Kap Stewart Formation (Jameson Land, East Greenland) has been studied by a combination of sedimentological and organic geochemical methods (LECO/Rock Eval, sulphur, gas chromatography) in order to assess the hydrocarbon source potential of the abundant and extensive lacustrine shale intervals present in the formation.The organic matter in the shales is a mixture of algal and higher plant remains (type I and III kerogen). An organic assemblage dominated by algal material, having a rich oil potential, occurs in an interval approximately 10–15 m thick in the uppermost part of the formation. This interval has an organic carbon content up to 10% and Hydrogen Index values up to 700. The interval is consistently traceable along the exposed margins and the central part of the basin. The deposition of the uppermost shale interval coincided with the largest expansion of the lake, during a period with a stratified water column and anoxic bottom-water conditions.Locally the rocks exposed are thermally postmature due to the thermal influence of dolerite sills which intruded the Kap Stewart Formation in Tertiary time. However, the organic-rich shale interval is beyond the influence of the sills and indicates a maturity prior to or in the early stages of oil generation.Calculations of the generative potential of the lacustrine source rocks suggest that significant amounts of petroleum may have been generated in those sediments which have undergone sufficient burial in the southern and central part of the basin. Here, the contemporaneously deposited delta front and barrier island sandstones can thus be considered as potential targets for future hydrocarbon exploration. This type of play may also be of importance in other North Atlantic basins with a similar basin history.