Geochemical characteristics of crude oils from the Sagara oil field, Shizuoka Prefecture, Japan

Abstract   Six oil samples collected from the Sagara oil field, Shizuoka Prefecture, were geochemically analyzed. Unlike the Niigata oils, the Sagara oils: (i) are low-sulphur light oils dominated by gasoline and kerosene fractions; (ii) have low values of environment index in light hydrocarbon compositions; (iii) have high Pr/ n -C₁₇ and low Ph/ n -C₁₈ ratios and high oleanane/hopane ratios; (iv) have high relative abundance of C₂₉ and low relative abundance of C₂₈ regular steranes; and (v) have 'light' stable carbon isotope compositions. These characteristics show that the source rocks of the Sagara oils contain mainly marine organic matter, but with more input of terrigenous organic matter deposited under more oxic conditions compared to those of the Niigata oils. The light carbon isotope compositions and the low relative abundance of C₂₈ regular steranes of the Sagara oils suggest that their source rock is not Miocene, but probably Paleogene in age. The Sagara oils probably migrated along faults from deeper parts of the basin.     

Lithological and physical properties of core samples from the Sagara oil field: Oil occurrence in Sagara core samples

Abstract   A drilling and coring investigation of the Sagara oil field, central Honshu, Japan, was conducted to contribute to the understanding of hydrocarbon migration processes in a forearc basin. Core samples were analyzed to determine lithology, physical properties (specifically gas permeability) and the characteristics of oil occurrence. Gas permeability values greater than approximately 10⁻¹¹ m² constitute the basic precondition for any lithology to serve as a potential fluid conduit or reservoir in the Sagara oil field. Cores recovered from the 200.6-m-deep borehole were primarily composed of alternating siltstone, sandstone and conglomerate, all of which are correlated to the late Miocene Sagara Group. Both sandstone and conglomerate can be classified into two types, carbonate-cemented and poorly to non-cemented, based on matrix material characteristics. Oil stains are generally absent in the former lithology and more common in the latter. Variations in physical properties with respect to gas permeability values are directly related to the presence and character of carbonate cement, with higher permeabilities common in poorly to non-cemented rocks. The relationships between lithology, oil-staining, cementation and permeability indicate that cementation preceded oil infiltration and that cementation processes exerted significant control on the evolution of the reservoir.     

Origins of hydrocarbons in the Sagara oil field, central Japan

Abstract   We collected free-gas and in situ fluid samples up to a depth of 200.6 m from the Sagara oil field, central Japan (34°44'N, 138°15'E), during the Sagara Drilling Program (SDP) and measured the concentrations and stable carbon isotopic compositions of CH₄ and C₂H₆ in the samples. A combination of the CH₄/C₂H₆ ratios with the carbon isotope ratios of methane indicates that the hydrocarbon gases are predominantly of thermogenic origin at all depths. The isotope signature of hydrocarbon gases of δ¹³      < δ¹³     suggests that these gases in the Sagara oil field are not generated by polymerization, but by the decomposition of organic materials.     

Formation mechanism of condensates,waxy and heavy oils in the southern margin of Junggar Basin,NW China

It is a challenge to determine the source and genetic relationship of condensate, waxy and heavy oils in one given complicated petroliferous area, where developed multiple sets of source rocks with different maturity and various chemical features.The central part of southern margin of Junggar Basin, NW China is such an example where there are condensates, light oils, normal density oils, heavy crude oils and natural gases. The formation mechanism of condensates has been seriously debated for long time;however, no study has integrated it with genetic types of waxy and heavy oils. Taking the central part of southern margin of Junggar Basin as a case, this study employs geological and geochemical methods to determine the formation mechanism of condensates,waxy and heavy oils in a complicated petroliferous area, and reveals the causes and geochemical processes of the co-occurrence of different types of crude oils in this region. Based on detailed geochemical analyses of more than 40 normal crude oils, light oils,condensates and heavy oils, it is found that the condensates are dominated by low carbon number n-alkanes and enriched in light naphthenics and aromatic hydrocarbons. Heptane values of these condensates range from 19% to 21%, isoheptane values from1.9 to 2.1, and toluene/n-heptane ratios from 1.5 to 2.0. The distribution of n-alkanes in the condensates presents a mirror image with high density waxy crude oils and heavy oils. Combined with the oil and gas-source correlations of the crude oils, condensates and natural gas, it is found that the condensates are product of evaporative fractionation and/or phase-controlled fractionation of reservoir crude oils which were derived from mature Cretaceous lacustrine source rocks in the relatively early stage. The waxy oils are the intermediate products of evaporative fractionation and/or phase-controlled fractionation of reservoir crude oils, while the heavy oils are in-situ residuals. Therefore, evaporative fractionation and/or phase-controlled fractionation would account for the formation of the condensate, light oil, waxy oil and heavy oil in the central part of southern margin of Junggar Basin, resulting in a great change of the content in terms of light alkanes, naphthenics and aromatics in condensates, followed by great uncertainties of toluene/n-heptane ratios due to migration and re-accumulation. The results suggest that the origin of the condensate cannot be simply concluded by its ratios of toluene/n-heptane and n-heptane/methylcyclohexane on the Thompson's cross-plot, it should be comprehensively determined by the aspects of geological background, thermal history of source rocks and petroleum generation,physical and chemical features of various crude oils and natural gas, vertical and lateral distribution of various crude oils in the study area.     

Vitrinite reflectance and consolidation characteristics of the post‐middle Miocene Forearc Basin in central and eastern Boso Peninsula,central Japan: Implications for basin subsidence

To understand the sedimentary development of the Boso Forearc Basin, central Japan, since ~ 3 Ma, we investigated paleothermal structure and consolidation trends in the central and eastern parts of the forearc basin through vitrinite reflectance measurements and consolidation tests. Vitrinite reflectance (R_m) was in the range 0.33 % to 0.61 % for the Miura Group in the central part of the forearc basin and 0.34 % to 0.41 % for the Miura and Kazusa Groups in the eastern. These values suggest a roughly uniform vitrinite reflectance for the Miura Group from the central to eastern parts. No significant vitrinite reflectance difference is observed across the ~ 3 Ma Kurotaki Unconformity in the eastern part of the basin. The consolidation yield stress (p_c) was calculated as 27.5 MPa and 32.2 MPa for the Kiyosumi and Amatsu Formations of the Miura Group in the eastern part, respectively. Both the p_c values are consistent quantitatively with represent the trend of the maximum overburden pressure estimated from the thickness and density of overlying sediments, and the difference in p_c is expected by the maximum burial depths of the strata at the sampling localities. Values of p_c in the eastern part of the basin increase with thickness of overlying sediment, showing no break across the Kurotaki Unconformity. Considering the eroded thickness of the Miura Group, the continuous trends in vitrinite reflectance and consolidation between the Miura and Kazusa Groups in the eastern part reflect the greater deposition of the eastern part of the Boso Forearc Basin since ~ 2.3 Ma.     

Potential petroleum sources and exploration directions around the Manjar Sag in the Tarim Basin

Since the discovery of the Tahe oilfield, it has been controversial on whether the main source rock is in the Cambrian or Middle-Upper Ordovician strata. In this paper, it is assumed that the crude oil from the Wells YM 2 and TD 2 was derived from the Middle-Upper Ordovician and Cambrian source rocks, respectively. We analyzed the biomarkers of the crude oil, asphalt-adsorbed hydrocarbon and saturated hydrocarbon in bitumen inclusions from the Lunnan and Hade areas in the North Uplift of the Tarim Basin. Results show that the ratios of tricyclic terpane C₂₁/C₂₃ in the crude oil, asphalt-adsorbed hydrocarbon and saturated hydrocarbon in bitumen inclusions are less than 1.0, indicating that they might be from Upper Ordovician source rocks; the ratios of C₂₈/(C₂₇+C₂₈+C₂₉) steranes in the saturated hydrocarbon from reservoir bitumen and bitumen inclusions are higher than 25, suggesting that they might come from the Cambrian source rocks, however, the ratios of C₂₈/(C₂₇+C₂₈+C₂₉) steranes in oil from the North Uplift are less than 25, suggesting that they might be sourced from the Upper Ordovician source rocks. These findings demonstrate that the sources of crude oil in the Tarim Basin are complicated. The chemical composition and carbon isotopes of Ordovician reservoired oil in the Tarim Basin indicated that the crude oil in the North Uplift (including the Tahe oilfield) and Tazhong Depression was within mixture areas of crude oil from the Wells YM 2 and TD 2 as the end members of the Cambrian and Middle-Upper Ordovician sourced oils, respectively. This observation suggests that the crude oil in the Ordovician strata is a mixture of oils from the Cambrian and Ordovician source rocks, with increasing contribution from the Cambrian source rocks from the southern slope of the North Uplift to northern slope of the Central Uplift of the Tarim Basin. Considering the lithology and sedimentary facies data, the spatial distribution of the Cambrian, Middle-Lower Ordovician and Upper Ordovician source rocks was reconstructed on the basis of seismic reflection characteristics, and high-quality source rocks were revealed to be mainly located in the slope belt of the basin and were longitudinally developed over the maximum flooding surface during the progressive-regressive cycle. Affected by the transformation of the tectonic framework in the basin, the overlays of source rocks in different regions are different and the distribution of oil and gas was determined by the initial basin sedimentary structure and later reformation process. The northern slope of the Central Uplift-Shuntuo-Gucheng areas would be a recent important target for oil and gas exploration, since they have been near the slope area for a long time.     

Genetic features of gas-condensate reservoirs in the Kekeya Field,southwest depression in the Tarim Basin,China

Oils, condensates and natural gases in the Kekeya Field, southeast depression of the Tarim Basin were studied for their geochemical characteristics. According to the distribution analysis of the C₂/C₃ values with C₁/C₂ values, C₂/C₃ values with C₁/C₃ values, as well as C₂/C₃ values with dryness index, there are two different types of natural gases in the studied field, which are spatially regularly distributed. One is the oil cracking gas, located on shallow reservoirs over X ₅ ² reservoir, namely Upper oil legs; the other is kerogen cracking gas, located on X ₇ ² reservoirs, X₈ reservoirs and E₂ k reservoirs, namely Lower oil legs. In addition, the distribution patterns of molar concentration of oils and condensates with different carbon numbers of the n-alkanes in the Kekeya Field indicate that the crude oils have experienced several kinds of secondary alterations, which were closely related to the charging of gaseous hydrocarbons after petroleum accumulation. These results indicate that, based on the research of δ ¹³C values of individual hydrocarbons, heptane values and isoheptane values of light hydrocarbons and aromatic maturity parameters for oils, condensates and natural gases, oils and gases were charged at different geological time in the Kekeya Field.     

Genetic features of gas-condensate reservoirs in the Kekeya Field,southwest depression in the Tarim Basin,China

Oils, condensates and natural gases in the Kekeya Field, southeast depression of the Tarim Basin were studied for their geochemical characteristics. According to the distribution analysis of the C₂/C₃ values with C₁/C₂ values, C₂/C₃ values with C₁/C₃ values, as well as C₂/C₃ values with dryness index, there are two different types of natural gases in the studied field, which are spatially regularly distributed. One is the oil cracking gas, located on shallow reservoirs over X ²₅ reservoir, namely Upper oil legs; the other is kerogen cracking gas, located on X ²₇ reservoirs, X₈ reservoirs and E₂ k reservoirs, namely Lower oil legs. In addition, the distribution patterns of molar concentration of oils and condensates with different carbon numbers of the n-alkanes in the Kekeya Field indicate that the crude oils have experienced several kinds of secondary alterations, which were closely related to the charging of gaseous hydrocarbons after petroleum accumulation. These results indicate that, based on the research of δ ¹³C values of individual hydrocarbons, heptane values and isoheptane values of light hydrocarbons and aromatic maturity parameters for oils, condensates and natural gases, oils and gases were charged at different geological time in the Kekeya Field.

     

Fluvial to bay sequence stratigraphy and seismic facies of the Cretaceous to Paleogene successions in the MITI Sanriku‐oki well and the vicinities,the Sanriku‐oki forearc basin,northeast Japan

This paper describes the significant depositional setting information derived from well and seismic survey data for the Upper Cretaceous to Lower Eocene forearc basin sediments in the central part of the Sanriku‐oki basin, which is regarded as a key area for elucidating the plate tectonic history of the Northeast Japan Arc. According to the results of well facies analysis utilizing cores, well logs and borehole images, the major depositional environments were of braided and meandering fluvial environments with sporadically intercalated marine incursion beds. Seismic facies, reflection terminations and isopach information provide the actual spatial distributions of fluvial channel zones flowing in a north–south trending direction. The transgression and regression cycles indicate that the Upper Cretaceous to Lower Eocene successions can be divided into thirteen depositional sequences (Sequences SrCr‐0 to SrCr‐5, and SrPg‐1 to SrPg‐7). These depositional sequences demonstrate three types of stacking patterns: Types A to C, each of which shows a succession mainly comprising a meandering fluvial system, a braided fluvial system with minor meandering aspects in the upper part, and major marine incursion beds in the middle part, respectively, although all show an overall transgressive to regressive succession. The Type C marine incursion beds characteristically comprise bay center and tidal‐dominated bay margin facies. Basin‐transecting long seismic sections demonstrate a roll up structure on the trench slope break (TSB) side of the basin. These facts suggest that during the Cretaceous to Eocene periods, the studied fluvial‐dominated forearc basin was sheltered by the uplifted TSB. The selective occurrences of the Type C sequences suggest that when a longer‐scale transgression occurred, especially in Santonian and early Campanian periods, a large bay basin was developed, creating accommodation space, which induced the deposition of the Cretaceous Kuji Group along the arc‐side basin margin.     

川东南焦石坝页岩气区现今地温场特征

四川盆地是我国重要的含油气区,关于盆地现今地温场的工作,前人已经做过一些研究.而对于近年来页岩气勘探取得突破性进展的川东南焦石坝地区,现今地温场的研究工作甚少.本文基于川东南高陡褶皱带焦石坝页岩气区新增的3口钻井的稳态测温数据和118块岩石样品热导率数据,计算了研究区的地温梯度和大地热流值.结合前人的研究成果,编制了研究区大地热流等值线图.结果表明,焦石坝页岩气区地温梯度介于24~34℃/km,大地热流值介于60~70mW·m~(-2)之间,与川中古隆起相似,属于地温高异常区.地温高异常缘于隆起区相对高的岩石热导率引起的浅部热流的重新分配.其次,与位于研究区东侧边界的齐岳山大断裂在燕山和喜山期的构造引起的热液活动有关.焦石坝页岩气区地温高异常对页岩气的解吸附速率具有促进作用,对提高采收率具有一定意义.     

Seismic-stratigraphic framework of the forearc basin off central Sumatra,Sunda Arc

New multichannel seismic reflection data provide information on the stratigraphic framework and geologic history of the forearc basin west of central Sumatra. We recognize six seismic-stratigraphic sequences that reflect the Cenozoic history and development of the outer continental shelf and forearc basin southeast of Nias Island. These sequences indicate several episodes of uplift of the subduction complex and filling of the forearc basin.Early in the development of this margin, Paleogene slope deposits prograded onto the adjacent basin floor. Onlapping this assemblage are two units interpreted as younger Paleogene(?) trough deposits. Uplift associated with rejuvenation of subduction in the late Oligocene led to erosion of the Sumatra shelf and formation of a regional unconformity.The early Miocene was a period of significant progradation. A Miocene limestone unit partly downlaps and partly onlaps the older Paleogene deposits. It is characterized by shallow shelf and oblique progradational facies passing into basin floor facies. A buried reef zone occurs near the shelf edge. The cutting of an erosional unconformity on the shelf and slope in late Miocene/early Pliocene time culminated this episode of deposition.In the late Pliocene, a large flexure developed at the western boundary of the basin, displacing the outer-arc ridge upward relative to the basin. Over 1 km of Pliocene to Recent sediment was deposited as a wedge in the deep western portion of the basin landward of the outer-arc ridge. These deposits are characterized by flat-lying, high-amplitude, continuous reflections that overstep the late Miocene unconformity. Up to 800 m of shallow-water limestone have been deposited on the shelf since mid-Pliocene time.     

Formation mechanisms of heavy oils in the Liaohe Western Depression,Bohai Gulf Basin

The Liaohe Oilfield in the Liaohe Western Depression of the Bohai Gulf Basin is the third-largest oil producing province and the largest heavy oil producing oilfield in China. A total of 65 oil samples,35 rock samples and 36 reservoir sandstone samples were collected and analyzed utilizing conventional geochemical and biogeochemical approaches to unravel the mechanisms of the formation of the heavy oils. Investigation of the oils with the lowest maturity compared with the oils in the Gaosheng and Niuxintuo oilfields indicates no apparent relation between the maturity and physical properties of the heavy oils. It is suggested that the heavy oil with primary origin is not likely the main mechanism re-sponsible for the majority of the heavy oils in the Liaohe Western Slope. The absence and/or depletion of n-alkanes etc.,with relatively low molecular weight and the occurrence of 25-norhopane series in the heavy oils as well as the relatively high acidity of the oils all suggest that the majority of the heavy oils once experienced secondary alteration. The fingerprints of the total scanning fluorescence (TSF) of the inner adsorbed hydrocarbons on the reservoir grains and the included hydrocarbons in fluid inclusions are similar to that of the normal oils in the area but are different from the outer adsorbed and reser-voired free oils at present,further indicating that most of the heavy oils are secondary in origin. Analyses of bacteria (microbes) in 7 oil samples indicate that anaerobic and hyperthermophilic Ar-chaeoglobus sp. are the dominant microbes relevant to oil biodegradation,which coincides with the shallow commercial gas reservoirs containing anaerobic bacteria derived gas in the Gaosheng and Leijia teotonic belts. The biodegradation most likely occurs at the water/oil interface,where the forma-tion water is essential for microbe removal and nutrient transportation. We think that biodegradation,water washing and oxidization are interrelated and are the main mechanisms for the formation of the heavy oils. Biodegradation was the predominant process with water washing being a prerequisite,and oxidization acting as a metabolic manifestation. This study provides unique approaches for further investigation of the formation mechanisms of heavy oils in general,and may provide some important insight for the exploration of shallow biogas in the area.     

Effects of rainfall on oil droplet size and the dispersion of spilled oil with application to Douglas Channel,British Columbia,Canada

Raindrops falling on the sea surface produce turbulence. The present study examined the influence of rain-induced turbulence on oil droplet size and dispersion of oil spills in Douglas Channel in British Columbia, Canada using hourly atmospheric data in 2011–2013. We examined three types of oils: a light oil (Cold Lake Diluent - CLD), and two heavy oils (Cold Lake Blend - CLB and Access Western Blend - AWB). We found that the turbulent energy dissipation rate produced by rainfalls is comparable to what is produced by wind-induced wave breaking in our study area. With the use of chemical dispersants, our results indicate that a heavy rainfall (rain rate > 20 mm h^? 1) can produce the maximum droplet size of 300 μm for light oil and 1000 μm for heavy oils, and it can disperse the light oil with fraction of 22–45% and the heavy oils of 8–13%, respectively. Heavy rainfalls could be a factor for the fate of oil spills in Douglas Channel, especially for a spill of light oil and the use of chemical dispersants.     

Petrography, diagenesis and provenance of Eocene Tyee Basin sandstones, southern Oregon Coast Range: New view from sequence stratigraphy

Abstract Sandstone petrography considered within a sequence stratigraphic framework provides a better understanding of the characteristics of the Eocene Tyee Basin, an accretionary and forearc sequence, southern Oregon Coast Range. Detailed comparison of the relative abundance of major framework grains documents a marked difference in the sandstone composition of each depositional sequence. Such a difference is mainly due to an abrupt change in provenance, from a local Klamath Mountains metasedimentary source to a more distant extrabasinal Idaho Batholith‐Clarno volcanic arc source. Furthermore, the composition of framework grains varies systematically from the lowstand systems tract to the highstand systems tract within a depositional sequence. This suggests that relative sea level change in the depositional basin, and tectonics in the source area, can affect the patterns of sedimentation and sandstone composition. In addition, the Eocene Tyee Basin sandstones have a down‐section distribution of authigenic minerals, consisting of early formed zeolites and late‐stage quartz, as well as a change in the abundance of smectite to mixed‐layer chlorite/smectite with increasing burial depth. The down‐section distribution of authigenic minerals is also causally linked to the compositional variation of framework grains in each depositional sequence with increasing burial temperature. Much primary porosity has been filled with these authigenic minerals, which diminishes the permeability of potential reservoir rocks. Reservoir‐quality porosities and permeabilities, however, are present locally in the basin. The development of these reservoir‐quality sandstones within the Eocene Tyee Basin sequence is due to a complex burial diagenesis, which is directly related to temporal and spatial variations in original detrital mineralogy, in sedimentation pattern, and in burial temperature in the basin.     

Study of genetic evolution of oil inclusion and density of surface oil by measurement of fluorescence lifetime of crude oil and oil inclusion

By using fluorescence lifetime image microscope (FLIM) and time-correlated single photon counting (TCSPC) technique, we measured fluorescence lifetime of crude oils with density of 0.9521–0.7606 g/cm³ and multiple petroleum inclusions from Tazhong uplift of Tarim Basin. As indicated by the test results, crude oil density is closely correlated with average fluorescence lifetime following the regression equation Y=–0.0319X+0.9411, which can thus be used to calculate density of oil inclusions in relation to fluorescence lifetime and density of corresponding surface crude. For type A oil inclusions showing brown-yellow fluorescence from Tazhong 1 well in Tarim Basin, their average fluorescence lifetime was found to be 2.144–2.765 ns, so the density of surface crude corresponding to crude trapping these oil inclusions is 0.852–0.873 g/cm³, indicating that they are matured oil inclusions trapped at earlier stage of oil formation. For type B oil inclusions with light yellow-white fluorescence, their average fluorescence lifetime was found to be 4.029–4.919 ns, so the density of surface crude corresponding to crude trapping these oil inclusions is 0.784–0.812 g/cm³, indicating that they are higher matured oil inclusions trapped at the second stage of oil formation. For type C oil inclusions showing light blue-green fluorescence, their average fluorescence lifetime was found to be 5.063–6.168 ns, so the density of surface crude corresponding to crude trapping these oil inclusions is 0.743–0.779 g/cm³, indicating that they are highly-matured light oil inclusions trapped at the third stage of oil formation.     

Carbon isotope characteristics,origin and distribution of the natural gases from the Tertiary salty lacustrine facies in the West Depression Region in the Qaidam Basin

Since the Meso-Cenozoic, controlled by paleoclimate, a series of fresh to brackish water basins and salt to semi-salt water basins were developed in wet climatic zones and in dry climate zones in China, respectively[1]. The geological and geochemical char…     

Forearc deformation and tectonic significance of the ultramafic Molucca central ridge, Talaud islands (Indonesia)

Abstract The Molucca Sea is a narrow basin located south of Mindanao (Philippines) and underlined by a north-south ophiolitic ridge. This ridge represents the outer ridge of the Sangihe subduction zone and emerges by uplift in the central part of the basin, in the Talaud Islands. Field studies indicate that forearc sediments rest uncomformably on (i) a dismembered ophiolitic series and (ii) thick melanges. Structural analysis indicates two deformation events, one of which is oriented east-west coaxial with the present state of strain. We interpret the earlier (N20°E) direction as a thrusting event that affected an ophiolitic basement associated with the edge of the Celebes Sea. Thrusting within the oceanic crust and sediments also generated olistostromes (melanges). The style of deformation is characterized by flattened rhombs of peridotites which exists in situ in the upper section of the crustal sequence and were also found inside the melange. Incipient Sangihe subduction around 15 Ma uplifted the deformed crust and buried the melanges beneath the forearc sediments. Recent east-west shortening during subduction of the Snellius Plateau reactivated the melanges within thrusts cutting the forearc series.     

Origin and accumulation of the oils from Bamianhe Oilfield, Bohai Bay Basin, Eastern China

Utilizing basic principles and methodologies of geology and organic geochemistry, kinetics of hydrocarbons generation and accumulation, quantitative assessment of crude oils sourced from different source rocks, and hydrocarbons migration pathways for the oils from the Bamianhe Oilfield, the Bohai Bay Basin, Eastern China are discussed. Results of oil-rock correlation showed that the oils were mainly derived from Es4 member (with buried depth >2700 m) of Niuzhuang and Guangli Sags within normal oil window though there is a little amount of mixed immature oils. Quantification of mixed oils with different sources indicated that mature oils account for about 80% of the total oils discovered and immature oils for only 20%. Migration of the oils sourced from the sags is controlled by predominant hydrocarbons migration passages determined by faults, unformalities and favored sandstone reservoir. Results of the origin and migration models for the oils have been recently further testified by considerable quantity of oils discovered in the Bamianhe area, which is obviously playing an important role in guiding further oil exploration.     

Controls on alkylphenol occurrence and distribution in oils from lacustrine rift basins in East China

Oils from two lacustrine rift basins in east China are thoroughly investigated using geochemical method to understand controls on alkylphenol occurrence and distribution in oils. Oils in the Lujiapu Depression, Kailu Basin are derived from the Cretaceous source rocks, and those in the Dongying De- pression, Bohai Bay Basin, from the Tertiary source rocks. All oils are experienced relatively short distance of migration and have similar maturity in each basin. Differences in homologue distributions from different oilfields are most likely caused by organic facies variation of source rocks. The oils in the Lujiapu Depression are characterized by high proportion of C3 alkylphenols (prefixes refer to the number of alkylcarbons joined to the aromatic ring of the phenol molecule) and low proportion of cre- sols and C2 alkylphenols compared to oils from the Dongying Depression. Alkylphenol isomer distri- bution is possibly affected by depositional environment especially for C3 alkylphenols. Dysoxic fresh- water environment is favorable for the formation of propyl or isopropyl substituted C3 alkylphenols, while highly reducing saline water is more suitable for trimethyl substituted C3 alkylphenols. Variations in alkylphenol concentrations within a petroleum system are controlled mainly by secondary migration processes with alkylphenol concentrations decreasing along migration direction. Interestingly, coupled with geological factors, a subtle change of alkylphenol concentrations can be applied to differentiate carrier systems. When oil migrates through sandy beds, concentrations of total alkylphenols decrease dramatically with migration distance, while such change is less significant when oil migrates vertically along faults. However, most isomer ratios potentially related to migration distance are not as effective as those alkylcarbazoles in migration diagnosis due to complicated affecting factors.     

A bathymetric overview of the Mariana forearc

Bathymetric data at a 200-m contour interval for the entire Mariana forearc, from south of 13°N to 25°N, permits the first comprehensive overview of this feature. The Mariana forearc represents a sediment-starved end-member. The forearc in its southern and central sections is divisible into a structurally complex eastern province and a less-deformed western province. Despite the absence of an accretionary complex the Mariana forearc has a well-defined outer-arc high; this probably results from a greater concentration of low-density serpentinized mantle lithosphere beneath the outer forearc relative to the inner forearc. This serpentinization gradient is coupled with differing deformational styles of thinner and more brittle lithosphere beneath the outer forearc compared to thicker and more ductile lithosphere beneath the inner forearc. The bathymetric data also support models calling for extension along-strike of the forearc, reflecting an increase in arc length accompanying the crescent-shaped opening of the Mariana Trough back-arc basin. Both northeast and northwest ridges and grabens can be identified, with the latter restricted to the southern part of the forearc and the former widely distributed in the central and northern forearc. Northeast-oriented extensional structures are supplanted northward by long, linear northwest-trending structures that are interpreted as left-lateral strike–slip faults. These variations in deformation along-strike of the forearc manifest a transition from nearly orthogonal convergence in the south to highly oblique convergence in the north.