Australian offshore natural hydrocarbon seepage studies,a review and re-evaluation

Surprisingly few natural hydrocarbon seeps have been identified in Australia's offshore basins despite studies spanning thirty years. Early studies of natural hydrocarbon seepage around the Australian margin were generally based on the geochemical analysis of stranded bitumens, water column geochemical ‘sniffer’ sampling, synthetic aperture radar or airborne laser fluorosensor. Later studies involved the integration of these remote sensing and geochemical techniques with multi-channel and shallow seismic. A review of these earlier studies indicates that many seepage interpretations need to be re-evaluated and that previous data sets, when placed in a global context, often represent normal background hydrocarbon levels. Low Recent burial and subsidence rates are not favourable for high rates of seepage. There are also difficulties in proving seepage on high energy, shallow carbonate shelves, where seabed features may be rapidly re-worked and modern marine signatures are overprinted on authigenic seep carbonates. Thus, the relatively few sites of proven natural hydrocarbon seepage in Australia's offshore sedimentary basins can be reconciled relative to their geological occurrences and the dominantly passive margin setting. Active thermogenic methane seepage on the Yampi Shelf, the only proven documented occurrence in Australia, is driven by deposition of a thick Late Tertiary carbonate succession and Late Miocene tectonic reactivation. Therefore, to increase the success of detecting and correctly interpreting natural hydrocarbon seepage, data need to be analysed and integrated within the context of the local geological setting, and with an understanding of what is observed globally.     

Characterization of natural hydrocarbon seepage in the South Caspian Sea off Iran using satellite SAR and geological data

Abstract

Two groups of oil slicks have been repeatedly detected in the Southern Caspian Sea, off Cape Sefidrud and close to the Iranian coast of the sea on the synthetic aperture radar (SAR) images acquired by the Sentinel-1A and Sentinel-1B satellites in April–June 2018. Analysis of the SAR images together with bathymetry, geological and geophysical data in geographic information system showed that these manifestations (oil slicks) visible on the sea surface have natural origin, related to the bottom seepage phenomenon and are associated with existing hydrocarbon system. Oil slicks are concentrated over the continental slope and related to local geological formations of the sedimentary cover having oil deposits related to paleo-delta of Sefidrud River. Our evidence shows that two seeps in this area are active and repeating. It is concluded that the SAR is an excellent tool for monitoring of seepage phenomenon. Moreover, results indicate that the use of remote methods to identify offshore natural oil seeps related to existing active petroleum system can be considered as a well-accepted approach to support oil and gas exploration in frontier areas such as the South Caspian Basin.     

Cold seeps at the salt front in the Lower Congo Basin II: The impact of spatial and temporal evolution of salt-tectonics on hydrocarbon seepage

This study investigates the distribution and evolution of seafloor seepage in the vicinity of the salt front, i.e., the seaward boundary of salt-induced deformation in the Lower Congo Basin (LCB). Seafloor topography, backscatter data and TV-sled observations indicate active fluid seepage from the seafloor directly at the salt front, whereas suspected seepage sites appear to be inactive at a distance of >10 km landward of the deformation front. High resolution multichannel seismic data give detailed information on the structural development of the area and its influence on the activity of individual seeps during the geologic evolution of the salt front region. The unimpeded migration of gas from fan deposits along sedimentary strata towards the base of the gas hydrate stability zone within topographic ridges associated with relatively young salt-tectonic deformation facilitates seafloor seepage at the salt front. Bright and flat spots within sedimentary successions suggest geological trapping of gas on the flanks of mature salt structures in the eastern part of the study area. Onlap structures associated with fan deposits which were formed after the onset of salt-tectonic deformation represent potential traps for gas, which may hinder gas migration towards seafloor seeps. Faults related to the thrusting of salt bodies seawards also disrupt along-strata gas migration pathways. Additionally, the development of an effective gas hydrate seal after the cessation of active salt-induced uplift and the near-surface location of salt bodies may hamper or prohibit seafloor seepage in areas of advanced salt-tectonic deformation. This process of seaward shifting active seafloor seepage may propagate as seaward migrating deformation affects Congo Fan deposits on the abyssal plain. These observations of the influence of the geologic evolution of the salt front area on seafloor seepage allows for a characterization of the large variety of hydrocarbon seepage activity throughout this compressional tectonic setting.     

Effect of sedimentary heterogeneities on hydrocarbon accumulations in the Permian Shanxi Formation,Ordos Basin,China: Insight from an integrated stratigraphic forward and petroleum system modelling

Sedimentary heterogeneities are ubiquitous in nature and occur over a range of scales from core, reservoir to basin scales. They may thus exert significant influences on hydrocarbon generation, migration and accumulation. The sedimentary heterogeneities of the Permian Shanxi Formation in the Ordos Basin, China were modelled using Sedsim, a stratigraphic forward modelling program. The simulation results were then used to construct a 3D petroleum system model using PetroMod. The effects of sedimentary heterogeneities on hydrocarbon accumulations were evaluated by comparing the integrated Sedsim-PetroMod model with the classic 3D basin model. The Sedsim simulation shows that considerable sedimentary heterogeneities are present within the Shanxi Formation, as a result of the interplay of the initial topography, tectonic subsidence, base level change and sediment inputs. A variety of lithologies were developed both laterally and vertically within the Shanxi Formation at kilometre and metre scales, respectively, with mudstones mainly developed in the depositional centre, while sandstones developed in the southern and northern margin areas. A typical source-ward retrogradation is well developed within the Lower Shanxi Formation.A base-case classic 3D basin model was constructed to quantify the Permian petroleum system in the Ordos Basin. The geological and thermal models were calibrated using Vr and borehole temperature data. The source rocks of the Upper Paleozoic became mature (R_o > 0.5%) and high mature (R_o > 1.2%) in the late Triassic and late Jurassic, respectively, in the central and southern areas. During the Early Cretaceous, a tectonically induced geothermal event occurred in the southern Ordos Basin. This caused the source rocks to reach over maturity (R_o > 2.0%) quite rapidly in the early Late Cretaceous in the central and southern areas. All the source rock transformation ratios (TR) at present are greater than 70% in the P₁ coal and P₁ mudstone layers with TR values approaching 100% in the central and southern areas. The transformation ratios of the P₁ limestone are close to 100% over the entire interval.In the base-case model, a large amount of hydrocarbons appear to have been expelled and migrated into the Shanxi Formation, but only a minor amount was accumulated to form reservoirs. In the model, the Shanxi Formation sandstone layer was set to be homogeneous vertically and there was no regional seal rocks present at the top of the Shanxi Formation. Therefore hydrocarbons could not be trapped effectively with only minor accumulations in some local structural highs where hydrocarbons are trapped both at the top and in the up-dip direction by the adjacent mudstone facies. In contrast, the integrated Sedsim-PetroMod model takes into account of the internal lithological and sedimentary facies heterogeneities within the Shanxi Formation, forming complex contiguous sandstone-mudstone stacking patterns. Hydrocarbons were found to have accumulated in multiple intervals of lithological traps within the Shanxi Formation. The results indicate that lithological distinctions, controlled by sedimentary heterogeneities in three dimensions can provide effective sealing in both the top and up-dip directions for hydrocarbon accumulations, with gas being mainly accumulated near the depocentre where lithological traps usually formed due to frequent oscillations of the lake level.     

南海北部莺歌海岭头岬近岸烃类渗漏喷口分布及气体地球化学

Natural hydrocarbon seeps in a marine environment are one of the important contributors to greenhouse gases in the atmosphere,including methane,which is significant to the global carbon cycling and climate change.Four hydrocarbon seep areas,the Lingtou Promontory,the Yinggehai Rivulet mouth,the Yazhou Bay and the Nanshan Promontory,occurring in the Yinggehai Basin delineate a near-shore gas bubble zone.The gas composition and geochemistry of venting bubbles and the spatial distribution of hydrocarbon seeps are surveyed on the near-shore Lingtou Promontory.The gas composition of the venting bubbles is mainly composed of CO_2,CH_4,N_2 and O_2,with minor amounts of non-methane hydrocarbons.The difference in the bubbles' composition is a possible consequence of gas exchange during bubble ascent.The seepage gases from the seafloor are characterized by a high CO_2 content(67.35%) and relatively positive δ~(13)C_(V_PDB) values(-0.49×10~(-3)-0.86×10~(-3)),indicating that the CO_2 is of inorganic origin.The relatively low CH_4 content(23%) and their negative δ~(13)C_(V-PDB) values(-34.43×10~(-3)--37.53×10~(-3)) and high ratios of C_1 content to C_(1-5) one(0.98-0.99)as well point to thermogenic gases.The hydrocarbon seeps on the 3.5 Hz sub-bottom profile display a linear arrangement and are sub-parallel to the No.1 fault,suggesting that the hydrocarbon seeps may be associated with fracture activity or weak zones and that the seepage gases migrate laterally from the central depression of the Yinggehai Basin.     

Hydrocarbon accumulation model for Neogene traps in the Chengdao area,Bohai Bay Basin,China

Chengdao is an offshore area in the Bohai Bay Basin that contains approximately 25.7 × 10⁸ bbl of oil and gas reserves within the sandstone reservoirs in Neogene strata. However, previous predictions of hydrocarbon accumulation in Neogene traps are inaccurate, resulting in a current failure rate of 50% when drilling for hydrocarbons in this area. To build an improved exploration model for Neogene traps, we select 92 traps from Neogene strata in the Chengdao area to quantify the filling degree, which is an indicator of hydrocarbon accumulation efficiency. The quantified filling degree is based on actual geological and exploration data and differs significantly among various trap types. The filling degree of traps also varies significantly with their structural locations and decreases generally from the northwest to the southeast along the Chengbei Fault zone. Vertically, the filling degree is highly heterogeneous, initially increasing from the bottom to the middle of Neogene strata and then decreasing towards the top of the strata. These Neogene hydrocarbon reservoirs are sourced from the Paleogene, and as they lay vertically away from the source rocks, their hydrocarbon enrichment is constrained largely by hydrocarbon migration distance and vertical migration pathways. The sealing capacity of faults and cap rocks, sandbody orientation and reservoir sedimentary facies determine the maximum column height, which in turn affects the amount of hydrocarbon accumulation within these traps. A scatter plot analysis of individual controls and volumetric filling for each trap type is compiled using multivariate linear regression analysis to quantify controls and the dominant control of hydrocarbon accumulation is determined.     

Bannu Basin,fold-and-thrust belt of northern Pakistan: Subsurface imaging and its implications for hydrocarbon exploration

The Trans Indus-Salt Range, located in northern Pakistan, is one of the most tectonically active fold-and-thrust belts and comprises three main regions: the Potwar-Salt Range, the Kohat-Surghar Range and the Bannu Basin-Khisor Range. Of these, the Bannu Basin is the least studied and only a handful of publically accessible datasets and publications are available. Recently made public 2D seismic profiles and well data from the Bannu Basin indicate the presence of salt as well as evidence for a main detachment surface which is Neoproterozoic in age. Our findings suggest that the Salt Range Formation could be the main detachment for the entire basin.Interpretation also shows a Miocene-Eocene basin-wide unconformity that marks the Himalayan orogenic event which separates the pre-Himalayan from the syn-Himalayan sedimentary units. On the basis of seismic reflection data, we conclude that the basin experienced three main tectonic settings. An early stage of pre-Himalayan passive tectonic environment is followed by the compressional Himalayan tectonics which resulted in uplifted areas sourcing the fluviatile fill of the subsided basin. During this time, sedimentation from the northern margin of the basin may have influenced the southward flow of salt. This is followed by a more recent stage of thrusting that produced folds and thrusts deforming all of the sedimentary units.Structural geometries suggest that prospective traps are developed mainly in the anticlines outlining the eastern and western boundaries of the Bannu Basin, as well as the southern zone of the basin. Furthermore, the presence of salt diapirism and transpression zones together with numerous oil seeps in and around the basin increase the probability of hydrocarbon accumulation and indicate great potential for future exploration.     

Automating conceptual models to easily assess trap integrity and oil preservation risks associated with fault reactivation

Extensive Neogene fault reactivation and leakage in the Timor Sea, Australian North-West Shelf, has long been identified as the likely cause for traps in the region being dry or underfilled, despite widespread evidence for hydrocarbon charge and larger palaeo-hydrocarbon columns than those preserved today. A structural model has been previously proposed (Gartrell et al., 2005) to explain the distribution of palaeo- and live hydrocarbon columns. This basic geometrical model is used to define the volume of closure that is protected from fault reactivation, thereby providing the potential for preserving hydrocarbons. Although the model is retrospectively successful in identifying which traps contain hydrocarbons, application to other areas is subjective. To assess the application of the Gartrell et al. (2005) concept a computational model has been generated and applied to a regional 3250 km² seismic interpretation, allowing sensitivity testing of the critical input parameters.The automation has allowed us to demonstrate that the model successfully identifies dry traps and derives reasonable approximations of hydrocarbon-water contacts in commercial accumulations. Therefore, the basic geometrical model is deemed valid to apply to other hydrocarbon provinces, both frontier and mature, that are adversely impacted by fault reactivation after hydrocarbon charge.     

Geologic control of natural marine hydrocarbon seep emissions, Coal Oil Point seep field, California

High-resolution sonar surveys, and a detailed subsurface model constructed from 3D seismic and well data allowed investigation of the relationship between the subsurface geology and gas-phase (methane) seepage for the Coal Oil Point (COP) seep field, one of the world’s largest and best-studied marine oil and gas seep fields, located over a producing hydrocarbon reservoir near Santa Barbara, California. In general, the relationship between terrestrial gas seepage, migration pathways, and hydrocarbon reservoirs has been difficult to assess, in part because the detection and mapping of gas seepage is problematic. For marine seepage, sonar surveys are an effective tool for mapping seep gas bubbles, and thus spatial distributions. Seepage in the COP seep field occurs in an east–west-trending zone about 3–4 km offshore, and in another zone about 1–2 km from shore. The farthest offshore seeps are mostly located near the crest of a major fold, and also along the trend of major faults. Significantly, because faults observed to cut the fold do not account for all the observed seepage, seepage must occur through fracture and joint systems that are difficult to detect, including intersecting faults and fault damage zones. Inshore seeps are concentrated within the hanging wall of a major reverse fault. The subsurface model lacks the resolution to identify specific structural sources in that area. Although to first order the spatial distribution of seeps generally is related to the major structures, other factors must also control their distribution. The region is known to be critically stressed, which would enhance hydraulic conductivity of favorably oriented faults, joints, and bedding planes. We propose that this process explains much of the remaining spatial distribution.     

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member,central depression,Southern Songliao Basin,China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (R_o) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, R_o >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at R_o >1%. Source rocks with TOC and R_o <0.8%, type-II₂ & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.     

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).     

Using iron speciation in authigenic carbonates from hydrocarbon seeps to trace variable redox conditions

Seepage of hydrocarbon-rich fluids out of the marine sedimentary column is characterized by temporal changes of flow intensity and resultant spatially variable redox conditions. Authigenic carbonates at marine hydrocarbon seeps provide excellent geological and geochemical archives that serve to explore seepage dynamics over time. In this study, we investigated the potential of Mössbuaer spectroscopy and Fe contents of seep-related authigenic carbonates from the Congo Fan, the Gulf of Mexico, and the Black Sea for reconstructing past redox conditions and fluid seepage activity at cold seeps. The Fe speciation observed by Mössbauer spectroscopy and Fe contents suggest that (1) the Congo Fan carbonates precipitated in a sulfidic environment, (2) the formation conditions of seep carbonates were variable at the Gulf of Mexico seep site, ranging from oxic to suboxic and anoxic and even spanning into the methanogenic zone, and (3) the stratified water column of the Black Sea or suboxic condition resulted in low Fe contents of Black Sea carbonates. The study reveals that Fe speciation can provide constraints on the wide range of redox conditions that imprinted seep carbonates during the life span of seepage. Similarly, Mössbauer spectroscopy – particularly when used in combination with the analysis of redox-sensitive elements – is a promising tool to trace variable redox conditions in marine paleoenvironments other than seeps.     

Shallow sediment deformation styles in north-western Campeche Knolls,Gulf of Mexico and their controls on the occurrence of hydrocarbon seepage

During German R/V Meteor M67/2 expedition to Campeche Knolls, southern Gulf of Mexico, a set of 2D high resolution seismic data was acquired to study the near-surface sediment structure and its relationship with hydrocarbon seepages in this salt province. The comprehensive survey covered 20 individual bathymetric highs or ridges and identified three principle structural types: Passive Type, Chaopopte Type, and Asymmetric Flap Type. The first type is the result of passive diapirism, whereas the latter two were initialized by a regional compressional event in the Miocene, but are later differently modified by salt tectonism. Chapopote Type structures appear as symmetrical domes, with uplifted coarse-grained Miocene sediments in their cores and rather thin syn-kinematic sediments covering the crests. Asymmetric Flap Type structures are also first folded as domes or ridges, but one flap later subsided together with salt evacuation, resulting in single uplifted monoclines. With the coarse-grained pre-kinematic sediments as reservoir units, both structural types can focus and accumulate hydrocarbons. The geometries of the structures suggest that hydrocarbons are accumulated in the center of the Chapopote Type structures and in the subsided flaps of the Asymmetric Flap Type structures. Hydrocarbon leakage from these thinly sealed reservoirs is regarded as the principle mechanism for the seepage in the study area, and accordingly the most seepage-prone positions are above these reservoirs. The seep locations suggested by analysis of sea-surface oil slick images of SAR satellite data are also examined in this study. These independently derived seep locations confirm the seepage-prone positions to be above the shallow buried reservoirs. This study suggest that the shallow sediment structures control the distribution of the hydrocarbon seeps of the north-western Campeche Knolls, although the hydrocarbons are sourced from the greater depth.     

南黄海盆地北部坳陷海底沉积物酸解烃类气体地球化学异常与深部油气属性

南黄海盆地北部坳陷海底沉积物酸解烃甲烷和酸解烃乙烷异常分布显示相同的特征,在西部存在1个高异常区,东部存在1个低异常区。酸解烃类气体的C1/(C2+C3)—δ13C1相关图显示酸解烃类气体属于热成因类型。烃类气体的C1—C2交会图和C1/(C2+C3)—C2/(C3+C4)交会图指示异常区的深部油气属性属于"油气并存"区和"干气"区,其中西部异常区以"油气并存"为主,东部异常区以"干气"为主。     

A new possible giant hydrocarbon generated formation: The Upper Triassic source rock in Southwestern Junggar Basin,NW China

The Triassic formation is a possible new giant hydrocarbon generated formation in Northwest China and Mid-Asia. Taking the Upper Triassic formation in the Sikeshu Sag in Junggar Basin as an example, based on the comprehensive analysis on the geochemical characteristics of the cores and the dark mudstone of the outcrops and reservoir formation conditions, we have evaluated the Upper Triassic source rocks by comparing with those in the Ulungu Depression, and reached the following findings. Firstly, the Upper Triassic formation is mainly composed of dark mudstone and sandy mudstone deposits, and the hydrocarbon source rock is mainly distributed in the middle and upper parts with a thickness range of 100–150 m and area of 3500 km². Secondly, the source rock, moderate in organic matter abundance (with TOC range of 1%–3%), has the material basis for hydrocarbon generation. Thirdly, the organic matter has high percentage of sapropelinite, and is dominated by type II₂. Fourthly, the degree of the thermal evolution is moderate, and the source rock with R_o higher than 0.7% has a distribution area of about 1800 km², providing the conditions of massive hydrocarbon generation. Fifthly, the source rock has great burial depth and wide distribution; the source rock with a R_o of higher than 0.7% and thickness of more than 100 m has an area of around 1400 km², implying huge resource potential. Sixthly, the next step exploration should focus on highly mature hydrocarbon generation central area in the Upper Triassic - Lower Jurassic in the east of the sag to search for and confirm favorable traps. The research findings have important reference value for promoting the resource status of, deepening the understanding of reservoir formation, and clarifying the exploration direction in the Sikeshu Sag and other periphery Mid-Asia areas.     

Integrated hydroacoustic flares and geomechanical characterization reveal potential hydrocarbon leakage pathways in the Perth Basin,Australia

Geoscience Australia (GA) and the Commonwealth Scientific and Industrial Research Organisation (CSIRO) conducted a marine survey including monitoring hydroacoustic flares in order to understand the natural leakage pathways in the offshore northern Perth Basin. 186 hydroacoustic contacts were encountered and classified and thirty two were interpreted as possible seeps or expulsion of gases from the subsurface. The contacts were typically distributed above areas of interpreted subsurface faulting. In the survey site Da (15 km²), nine probable seeps and sixteen other contacts were interpreted and are aligned with a fault segment (A2) interpreted on 2D seismic reflection data. The segment A2 is part of a major N–NNW trending fault system intersecting the sedimentary sequence from the near seabed to the Permian units, including the Kockatea Shale source rock located in the oil window. Evaluation of the stress state on the fault segment A2 suggests that it is not critically stressed and therefore not likely prone to reactivation and dilation and vertical leakage under the modelled stress field. We propose that fault segment A2 acts as a baffle delimiting a migration pathway in the wall rock and permitting hydrocarbons generated from the source rock to overcome capillary entry pressures of the overlying marginal seals. The interpreted seeps could therefore be associated with intraformational vertical migration in the wall rock focused by the faults.     

Hydrocarbon prospects across Narmada-Tapti rift in Deccan trap, central India: Inferences from integrated interpretation of magnetotelluric and geochemical prospecting studies

As the Mesozoic sediments contribute most of the oil and gas reserves of the world, we present an integrated interpretation approach using magnetotellurics (MT) and surface geochemical prospecting studies to demarcate hydrocarbon prospective Gondwana (Mesozoic) formations underneath the Deccan flood basalts of Late Cretaceous age across Narmada-Tapti rift (between Bhusawal and Barwah) in Central India. The MT interpretation shows deep (∼5 km) basement structure between southern and central part of the MT profile however, it gradually becomes shallower to either ends of the profile with a predominant basement depth reduction in the northern end compared to the southern end. The geophysical results suggest thick (2-3.5 km) Mesozoic sediments in the area characterized by deep basement structure. The geochemical analysis of the near surface soil samples indicate higher concentrations of light gaseous hydrocarbons constituents over the area marked with thick sub-basalt Mesozoic formations. Analyses of the geochemical data imply that these hydrocarbons are genetically related, generated from a thermogenic source and these samples fall in the oil-producing zone. The temperature-depth estimations in the region supports favorable temperature conditions (80-120 °C) for oil generation at basement depths.     

Oyster patch reefs as indicators of fossil hydrocarbon seeps induced by synsedimentary faults

The Late Jurassic deposits of the Boulonnais area (N-France) represent the proximal lateral-equivalent of the Kimmeridge Clay Formation; they accumulated on a clastic-dominated ramp subject to synsedimentary faulting as a result of the Atlantic Ocean rifting. In the Gris-Nez Cape area, i.e., close to the northern border fault zone of the Jurassic basin, the Late Jurassic sequence contains small-dimensioned oyster patch reefs (<1 m) that are specifically observed at the base of an abrupt deepening trend in the depositional sequence induced by well-defined pulses of normal fault activity. Petrographic analysis of these patch reefs shows that they are exclusively composed of Nanogyra nana embedded in a microsparitic calcite matrix. ™¹³C measurements, carried out within both the matrix and the shells, display significantly lower values in the matrix compared to the oyster shells which suggests that the carbonate matrix precipitation was involving a carbon source different from marine dissolved inorganic carbon, most probably related to sulfate reduction, which is evidenced by light ™³⁴S in pyrites. Similarities but also differences with lucinid-rich bioconstructions, namely, the Late Jurassic pseudo-bioherms of Beauvoisin (SE-France) suggest that the patch reefs developed at hydrocarbon seeps are related to synsedimentary faults. The extensional block-faulting segmentation of the northern margin of the Boulonnais Basin in Late Jurassic times is thus believed to have induced a sort of small-dimension hydrocarbon seepage field, recorded by the patch reef distribution.     

琼东南盆地深水区崖城组生成天然气的化学动力学及其应用

The natural gas generation process is simulated by heating source rocks of the Yacheng Formation, including the onshore-offshore mudstone and coal with kerogens of Type II_2-III in the Qiongdongnan Basin. The aim is to quantify the natural gas generation from the Yacheng Formation and to evaluate the geological prediction and kinetic parameters using an optimization procedure based on the basin modeling of the shallow-water area. For this, the hydrocarbons produced have been grouped into four classes(C_1, C_2, C_3 and C_(4-6)). The results show that the onset temperature of methane generation is predicted to occur at 110℃ during the thermal history of sediments since 5.3 Ma by using data extrapolation. The hydrocarbon potential for ethane, propane and heavy gaseous hydrocarbons(C_(4-6)) is found to be almost exhausted at geological temperature of 200℃ when the transformation ratio(TR) is over 0.8, but for which methane is determined to be about 0.5 in the shallow-water area. In contrast, the end temperature of the methane generation in the deep-water area was over 300℃ with a TR over 0.8. It plays an important role in the natural gas exploration of the deep-water basin and other basins in the broad ocean areas of China. Therefore, the natural gas exploration for the deep-water area in the Qiongdongnan Basin shall first aim at the structural traps in the Ledong, Lingshui and Beijiao sags, and in the forward direction of the structure around the sags, and then gradually develop toward the non-structural trap in the deep-water area basin of the broad ocean areas of China.     

A basin modeling and organic geochemistry study in the Vallecitos syncline,San Joaquin Basin,California

The Vallecitos syncline is a westerly structural extension of the San Joaquin Basin. The Vallecitos oil field, comprised of eight separate areas that produce from Cretaceous and Paleogene reservoirs, accounted for 5.4 MMB of oil and 5.6 BCF associated of gas through 2010. However, exploration for oil and gas in the Vallecitos area is challenging due to structural complexity and limited data. The purpose of this study is to evaluate whether source rocks are actively generating petroleum in the Vallecitos syncline and to improve our understanding of burial history and timing of hydrocarbon generation. We conducted biomarker analysis on twenty-two oil samples from the Vallecitos syncline. Source-related biomarkers show two genetic groups of oil, which originated from two different source rocks. These results differ from earlier published interpretations in which the Kreyenhagen Formation is the only source rock in the Vallecitos syncline, and suggest that the Cretaceous Moreno Formation in the syncline also is an active source rock.Stratigraphic evidence and modeling suggest that late Cenozoic episodes of erosion due to folding and uplift removed significant overburden on the flanks of the syncline. To better understand the petroleum systems and clarify the total active source rocks in the area, 2D burial histories were generated through the Vallecitos syncline. A published cross-section through the deepest part of the syncline was selected to conduct thermal history, basin evolution, and migration analyses. The 2D model results indicate that the lower Kreyenhagen Formation has various maturities within the formation at different locations in the present-day syncline. The basal part of the Kreyenhagen Formation is in the dry gas window and maturity decreases away from the central part to the flanks. It remains immature along shallow portions of the present-day flanks. In contrast, the basal part of the Moreno Formation achieved extremely high maturity (past the gas generation zone) but is in the oil generation zone on the flanks of the syncline at shallow depth. All of our geochemical and 2D model results suggest that there are two active source rocks in the Vallecitos syncline. Accordingly, we propose that there are two active petroleum systems in the Vallecitos syncline.