Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.     

Controls of oil family distribution and composition in nonmarine petroleum systems: A case study from Inner Mongolia Erlian basin,Northern China

The Erlian basin is a continental rift basin located in Inner Mongolia, Northern China. It is a typical representative of Cretaceous Northeast Asian Rift System, which includes many small petroliferous basins in Mongolia Republic and Northern China. Although Lower Cretaceous source rocks are understood to be most important in the Erlian petroleum systems, the precise identification of these source rock intervals and their determination on oil families distribution and composition are poorly understood in this tectonically complicated, nonmarine basin. New bulk data have been gathered from source rock intervals, oil sands and crude oil samples in eight main oil-producing subbasins. Geochemical analyses indicate that Lower Cretaceous Aershan formation (K₁ba) and Tengger 1 formation (K₁bt₁) are two main source intervals in the Erlian basin and their source rock facies vary from profundal lacustrine to marginal lacustrine according to biomarker and trace elements calibration, the profundal lacustrine facies is characterised by brackish water and anoxic environment, which is similar to their correlative oils (Family 1 oils). The marginal lacustrine facies is characterised by freshwater and suboxic environment, which sourced the most common Family 2 oils. Meanwhile, different maturation processes exercise the second control on oil groups and their compositions, the profundal lacustrine source rocks characterised by their sulphur-rich kerogens lead to two oil groups (group 1 and group 2 oils), whose maturity range from low to normal; while, the marginal lacustrine source rock only lead to normal-maturity oils. At last, biodegradation affected the composition of a certain oils and formed group 4 heavy oils. In addition, short migration distance in small subbasins made the contamination or fractionation less notable in the Erlian basin.     

Hydrocarbon potential of the Sargelu Formation,North Iraq

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg?HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI?=?3^? to 3⁺, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R₂₈ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.     

Correlation of crude oils and oil components from reservoirs and source rocks using carbon isotopic compositions of individual n-alkanes in the Tazhong and Tabei Uplift of the Tarim Basin,China

Carbon isotopic compositions were determined by GC–IRMS for individual n-alkanes in crude oils and the free, adsorbed and inclusion oils recovered by sequential extraction from reservoir rocks in the Tazhong Uplift and Tahe oilfield in the Tabei Uplift of Tarim Basin as well as extracts of the Cambrian–Ordovician source rocks in the basin. The variations of the δ¹³C values of individual n-alkanes among the 15 oils from the Tazhong Uplift and among the 15 oils from the Triassic and Carboniferous sandstone reservoirs and the 21 oils from the Ordovician carbonate reservoirs in the Tahe oilfield demonstrate that these marine oils are derived from two end member source rocks. The major proportion of these marine oils is derived from the type A source rocks with low δ¹³C values while a minor proportion is derived from the type B source rocks with high δ¹³C values. Type A source rocks are within either the Cambrian–Lower Ordovician or the Middle–Upper Ordovician strata (not drilled so far) while type B source rocks are within the Cambrian–Lower Ordovician strata, as found in boreholes TD2 and Fang 1. In addition, the three oils from the Cretaceous sandstone reservoirs in the Tahe oilfield with exceptionally high Pr/Ph ratio and δ¹³C values of individual n-alkanes are derived, or mainly derived, from the Triassic–Jurassic terrigenous source rocks located in Quka Depression.The difference of the δ¹³C values of individual n-alkanes among the free, adsorbed and inclusion oils in the reservoir rocks and corresponding crude oils reflects source variation during the reservoir filling process. In general, the initial oil charge is derived from the type B source rocks with high δ¹³C values while the later oil charge is derived from the type A source rocks with low δ¹³C values.The δ¹³C values of individual n-alkanes do not simply correlate with the biomarker parameters for the marine oils in the Tazhong Uplift and Tahe oilfield, suggesting that molecular parameters alone are not adequate for reliable oil-source correlation for high maturity oils with complex mixing.     

Potentiality of Paleocene source rocks and their contribution in generating the accumulated oil in the Eocene Pila Spi Reservoir in Taq Taq Oil Field, Kurdistan Region, Iraq

The organic matters within the Paleocene Aaliji and Kolosh Formations in the well TT-04, Taq Taq Oil Field in Kurdistan Region, NE Iraq have been studied optically and also analytically by means of pyrolysis, Gas Chromatography (GC), and Gas Chromatography/Mass Spectrometry (GC/MS). Amorphous organic matters seemed to be the dominant component of the extracted organic matters within the studied section with an obvious increase of the Phytoclasts at the upper part of Kolosh Formation. Thermal Alteration Index, vitrinite reflectance, pyrolysis, and gas chromatography data all indicated the maturity of the lower part from the studied layers (known generally as Aaliji/Kolosh) and within the early stages of oil generation. Oil–source correlation indicates the possibility of contribution of the Paleocene source rocks in generating the accumulated oil in the Eocene Pila Spi reservoir in the field which also appeared to be a mature and of marine-to-mixed carbonate source. Oil–oil correlation between the oil in Pila Spi and the oil in the Upper Cretaceous reservoirs showed the possibility of existence of more than one source for the two oils. GC/MS analysis for the Pila Spi oil indicated the effect of biodegradation which may be considered as one of the reasons for being the American Petroleum Institute (API) of this oil about 24° while the oil in the Cretaceous reservoirs is of more than 47° API.     

Modeling of gas generation from the Alam El-Bueib formation in the Shoushan Basin, northern Western Desert of Egypt

The Shoushan Basin is an important hydrocarbon province in the northern Western Desert, Egypt, but the burial/thermal histories for most of the source rocks in the basin have not been assigned yet. In this study, subsurface samples from selected wells were collected to characterize the source rocks of Alam El-Bueib Formation and to study thermal history in the Shoushan Basin. The Lower Cretaceous Alam El-Bueib Formation is widespread in the Shoushan Basin, which is composed mainly of shales and sandstones with minor carbonate rocks deposited in a marine environment. The gas generative potential of the Lower Cretaceous Alam El-Bueib Formation in the Shoushan Basin was evaluated by Rock–Eval pyrolysis. Most samples contain sufficient type III organic matter to be considered gas prone. Vitrinite reflectance was measured at eight stratigraphic levels (Jurassic–Cretaceous). Vitrinite reflectance profiles show a general increase of vitrinite reflectance with depth. Vitrinite reflectance values of Alam El-Bueib Formation range between 0.70 and 0.87 VRr %, indicating a thermal maturity level sufficient for hydrocarbon generation. Thermal maturity and burial histories models predict that the Alam El-Bueib source rock entered the mid-mature stage for hydrocarbon generation in the Tertiary. These models indicate that the onset of gas generation from the Alam El-Bueib source rock began in the Paleocene (60 Ma), and the maximum volume of gas generation occurred during the Pliocene (3–2 Ma).     

Geochemical Investigation of the Cretaceous Crude Oil Reservoirs and Source Rock Samples in One of the Abadan Plain Oilfields, SW Iran

Crude oil and source rock samples from one of the main oilfields of the Abadan Plain, Zagros, Iran were analyzed geochemically. Rock-Eval pyrolysis was conducted on Kazhdumi (Upper Cretaceous) and Gadvan (Lower Cretaceous) formations, which are the probable source rocks for the oil in the region. The results indicated that the Kazhdumi Formation can be classified as a fair-to-excellent source rock, while the Gadvan Formation can be identified as having poor-to-good source rock in the basin. Based on the cross-plots of HI versus OI and S2 versus TOC, types II and III kerogen were identified from studied source samples in the area. Determination of the main fraction percentages of the Sarvak and Fahliyan crude oils represented that the oils from the Sarvak reservoir are paraffinic-naphthenic and aromatic-intermediate, whilst that from the Fahliyan reservoir is paraffinic and paraffinic-naphthenic. Biomarker ratios of the saturated fractions of oil from both reservoirs indicate that the source rocks formed in reducing marine environments with carbonate-shale lithology. Furthermore, biomarker data helped to distinguish the degree of biodegradation in the studied oils. According to geochemical analysis, oil samples from the Fahliyan reservoir were generated at a higher thermal maturity than the Sarvak reservoir samples.     

乌兰花凹陷原油特征及成因

乌兰花凹陷是二连盆地南部新发现的富油凹陷,对乌兰花凹陷原油物理性质和地球化学性质进行了系统的分析以揭示其特征及来源。原油物理性质显示,乌兰花凹陷原油比重（API gravity）介于20.2°~40.0°之间,主体为正常原油。原油生物标志化合物参数表明,不同构造带之间原油特征存在差异,可以划分为两类原油。一类以土牧尔构造带原油为主,具有低姥值比（Pr/Ph）和C₂₁/C₂₃三环萜烷,相对较高的伽马蜡烷/C₃₁藿烷和规则甾烷/C₃₀藿烷的特征,原油主要为烃源岩在成熟阶段早期的产物,主要以藻类来源为主。另一类原油包括赛乌苏和红井构造带原油,具有高姥值比（Pr/Ph）和C₂₁/C₂₃三环萜烷,相对较低的伽马蜡烷/C₃₁藿烷和规则甾烷/C₃₀藿烷,主要为陆源有机质和藻类有机质混合来源,原油具有更高的成熟度。原油碳同位素和正构烷烃单体烃碳同位素表明这两类原油应是一套烃源岩在不同成熟阶段的产物,原油主要来源于南洼槽阿尔善组烃源岩。阿尔善组烃源岩的非均质性和成熟度导致了两类原油的差异。      

The origin of oil in the Cretaceous succession from the South Pars Oil Layer of the Persian Gulf

The origin of the oil in Barremian–Hauterivian and Albian age source rock samples from two oil wells (SPO-2 and SPO-3) in the South Pars oil field has been investigated by analyzing the quantity of total organic carbon (TOC) and thermal maturity of organic matter (OM). The source rocks were found in the interval 1,000–1,044 m for the Kazhdumi Formation (Albian) and 1,157–1,230 m for the Gadvan Formation (Barremian–Hauterivian). Elemental analysis was carried out on 36 samples from the source rock candidates (Gadvan and Kazhdumi formations) of the Cretaceous succession of the South Pars Oil Layer (SPOL). This analysis indicated that the OM of the Barremian–Hauterivian and Albian samples in the SPOL was composed of kerogen Types II and II–III, respectively. The average TOC of analyzed samples is less than 1 wt%, suggesting that the Cretaceous source rocks are poor hydrocarbon (HC) producers. Thermal maturity and Ro values revealed that more than 90 % of oil samples are immature. The source of the analyzed samples taken from Gadvan and Kazhdumi formations most likely contained a content high in mixed plant and marine algal OM deposited under oxic to suboxic bottom water conditions. The Pristane/nC₁₇ versus Phytane/nC₁₈ diagram showed Type II–III kerogen of mixture environments for source rock samples from the SPOL. Burial history modeling indicates that at the end of the Cretaceous time, pre-Permian sediments remained immature in the Qatar Arch. Therefore, lateral migration of HC from the nearby Cretaceous source rock kitchens toward the north and south of the Qatar Arch is the most probable origin for the significant oils in the SPOL.     

Origin of oils in the Eastern Papuan Basin,Papua New Guinea

The geochemical characteristics of 16 oils/condensates/seep oil/oil shows (collectively called oils) from the Eastern Papuan Basin (EPB) and one seep oil from the Western Papuan Basin (WPB) are integrated with data from previous studies of oils, fluid inclusion oils and solid bitumens from the EPB and WPB, Papua New Guinea. The combined set of samples can be divided in two major families of hydrocarbons. The Family A oils, mostly occurring in the WPB region, were generated from clay rich marine source rocks, containing predominantly terrigenous higher plant derived organic matter (OM) deposited in a sub-oxic to oxic environment. Source rock(s) for Family A oils are likely to be of Middle to Upper Jurassic, e.g., the Upper Jurassic Imburu Formation. The Family B oils, distributed mainly in the EPB region, were generated from Cretaceous or younger marine carbonate source rock(s) deposited under anoxic to sub-oxic conditions, and containing predominantly prokaryotic OM with some terrigenous higher plant inputs. The EPB natural gases analyzed in this study may be co-genetic to the co-occurring Family B oils in the EPB. Both Family A and B oils were generated at similar thermal maturities of 1.0–1.3% vitrinite reflectance equivalent. Although no source interval to date has been firmly identified in the EPB, post-Jurassic strata are a viable option, because (1) Late Cretaceous and Paleogene carbonate and clastic marine sediments including possible source lithologies are present, and (2) this section of the Papuan Basin sustained rapid sedimentation and tectonic loading, particularly in the Cenozoic.     

苏北盆地盐城凹陷兴桥1井烃源岩特征及气源分析

盐城凹陷兴桥1井钻遇二叠系孤峰组和栖霞组两套烃源岩。孤峰组为暗色泥岩,视厚度11.3m,有机碳最高为1.44%,平均0.74%,有机质类型偏向Ⅲ型;栖霞组为暗色碳酸盐岩,厚度较大,其中TOC>0.4%的地层的折算厚度大于42m,有机质类型主要为Ⅱ2型。这两套烃源岩的有机质热演化程度较低,至今仍具一定的生烃能力。兴桥1井上白垩统浦口组及下二叠统栖霞组见到多层气显示,浦口组的气源可能为深部二叠系,栖霞组的气体则可能受到更深部寒武系气源的侵入。     

海拉尔盆地呼和湖凹陷下白垩统烃源岩地球化学特征及热演化史

呼和湖凹陷下白垩统烃源岩生油条件好,油气资源潜力大.利用研究区7口钻井270个热解资料和125个镜质体反射率数据,分析了下白垩统烃源岩地球化学特征及热演化史.下白垩统烃源岩有机质类型主要为Ⅲ-Ⅱ2型干酪根,现今热演化程度具有中间高、四周低的特点.主力烃源岩层南屯组属于中等-好烃源岩,在约128 Ma进入生烃门限,现今处于高成熟-生气阶段.大磨拐河组属于差-中等烃源岩,在约124 Ma进入生烃门限,现今处于中等-低成熟阶段,大磨拐河组二段烃源岩至今未进入生烃高峰.热史模拟表明呼和湖凹陷在伊敏组沉积晚期达到最大古地温,地温演化具有先升高后降低的特点.从南屯组沉积至今,地温梯度先升高到50~55℃/km,后逐渐降低为现今的35.4℃/km.早白垩世以来较高的地温场对油气生成、成藏起控制作用.包裹体均一温度结合热演化史结果表明126~87 Ma（伊敏组沉积时期）应是呼和湖凹陷油气主成藏期.晚白垩世以来盆地发生抬升,温度降低,烃源岩生烃强度减弱.      

准噶尔盆地永进地区油源研究

在分析和归纳可能烃源岩的有机地化特征并对原油样品进行分析测试的基础上,主要运用生物标志物和稳定碳同位素指标或参数,首次对准噶尔盆地永进地区原油的来源进行了系统研究,认为中二叠统和中下侏罗统烃源岩是为该地区提供油源的主要烃源岩,其次为下二叠统烃源岩,并可能有白垩系烃源岩的贡献。其中,中侏罗统西山窑组煤层之上及大部分白垩系储层中的正常原油主要来自中二叠统烃源岩;煤层之下及下侏罗统三工河组储层中的正常原油主要来自中下侏罗统烃源岩;在现今油藏中所占比例较小并已发生强烈生物降解的原油来自下二叠统烃源岩;永6井白垩系储层中的原油可能来自下白垩统烃源岩,但该套烃源岩的供烃规模可能较小。     

Organic geochemical characteristics of crude oils from the Masila Basin, eastern Yemen

The Masila Basin is an important hydrocarbon province in Yemen, but the origin of hydrocarbons and their generation history are not fully understood. In this regard, 10 crude oils from different petroleum reservoir sections in the Masila Basin were characterized by a variety of biomarker and non-biomarker parameters using GC, GC-MS and stable carbon isotope techniques. Oils from the Masila Basin display pristane/phytane (Pr/Ph) ratios ranging from 1.7 to 2.0, low sulfur content, high C₃₅ homohopane index, relatively high C₂₇ sterane concentrations and relatively high tricyclic terpanes suggesting a marine clay source rock that was deposited in mildly anoxic to suboxic conditions with dominantly algal organic matter. C₂₉ 20S/(20S + 20R) steranes and ββ/(ββ + αα) sterane ratios indicate that the Masila oils have reached peak oil window maturity. Another related feature of these oils is the absence of 18α (H)-oleanane, which suggests a source age older than Cretaceous. The carbon isotope compositions are similar to those of the potential source rocks, which range from −25.4‰ to −28.3‰, indicating a marine environment. The new data presented in this paper suggest that the Masila oils constitute one oil family and that the oil originated from the Upper Jurassic Madbi source rock in the basin.     

Fluorescence micro-spectrometry of synthetic and natural hydrocarbon fluid inclusions: crude oil chemistry,density and application to petroleum migration

The fluorescence spectra of crude oils, synthesized as hydrocarbon fluid inclusions (hcfi) in NaCI crystals, have been recorded and correlated with crude oil chemical analysis. The crude oils represent a wide range in total hydrocarbons, saturate and aromatic fractions, and resin-asphaltene concentration. The fluorescence properties (Lambda max and Q) of the hydrocarbon fluid inclusions display a systematic red shift to longer wavelengths from 440 nm to 595 nm with increasing aromatic content and increasing concentration of NSO-bearing compounds. A positive correlation also exists between Lmax-Q and the thermal maturity parameters nC17/pristane and nC₁₈/phytane. First order linear regression equations provide a method for constraining the chemical composition of natural hydrocarbon fluid inclusions. Lmax and Q correlate positively with oil density (°API), providing for an indirect method of estimating the API of a natural hydrocarbon fluid inclusion assemblage. Fluorescence spectra of non-biodegraded crude oils from the Upper Devonian Birdbear Formation, Saskatchewan, Canada, have been correlated with regionally widespread hcfi within carbonate carrier beds and reservoir rocks of the same formation. The two most dominant types of hcfi spectra match well with the fluorescence spectra from crude oils within the Birdbear Formation. A third, less common population of very-blue fluorescing hcfi (Lmax=415440 nm, Q ≤ 0.10) also occur within fractures, intercrystalfne cements or in fossil overgrowths. The Lmax-Q-API-chemical correlations establised for the synthetic hcfi suggests that the °API of these inclusions is probably > 45° and the saturate/aromatic ratio ranges from 3.2 to 5.1. Spectra from hcfi within quartz overgrowths and cements, fractures and carbonate cements from sandstone reservoirs in the Jeanne d'Arc Basin offshore Newfoundland, compared with fluorescence spectra of crude oils suggests that some of the reservoirs may have been filled by a relatively low maturity oil and then a higher maturity oil. This is reflected in the intermediate spectra of the crude oils relative to the spectra of two separate hcfi events. Other reservoirs appear to have been charged with a relatively high gravity oil which was later biodegraded. This is marked by a blue region spectra for the hcfi compared with a red-shifted spectra for the crude oil (°API = 19). The API of the original unaltered oil which charged the reservoir is estimated to be between 32 and 38° using the Lmax-Q-API relationship established for the synthetic hcfi.     

Biological marker characteristics of oils and asphalts from carbonate source rocks in a rapidly subsiding graben,Dead Sea,Israel

A detailed GC/MS study of biological marker compounds in the saturated and aromatic hydrocarbon fractions of oils and asphalts from the Dead Sea area, Israel, provided decisive information to the solution of a long-lasting controversy by showing that the asphalts are products of early generation in an immature stage from the same type of carbonate source rock which generated more mature oils. The asphalts are not biodegraded residues of the oils.Oils from six different wells, and asphalts from wells, outcrops, and a floating block from the Dead Sea all have very similar sterane and triterpane patterns. They all lack rearranged steranes (diasteranes) indicating a carbonate source matrix and compare reasonably well with a sample of Upper Cretaceous bituminous chalk from Nebi Musa. The main difference between the oils and the asphalts is a significantly higher triaromatic to mono- plus triaromatic steroid hydrocarbon ratio in the former. This is explained as a result of rapid subsidence and heating of their source rock close to the deep parts of the Dead Sea graben. The oils thus were generated in the more deeply buried source rock blocks under the graben fill, whereas the asphalts either originate from an immature source rock section closer to the graben rims or represent an earlier phase of generation and expulsion.This study also provides general information on the evolution of biological markers in carbonate source rocks. Low-activation-energy processes, like isomerisation of steranes, appear to occur much faster at low temperatures than in shales. The high sulfur content and less cross-linking of the biogenic organic matter into a complex kerogen structure are suggested to be responsible for this. Care should be taken when using only sterane isomerisation to assess the maturity of hydrocarbons from carbonate rocks and of carbonate-derived oils.     

1D PetroMod software modeling of the Basrah oil fields, Southern Iraq

1D (Petromod) hydrocarbon charge modeling and source rock characterization of the Lower Cretaceous and Upper Jurassic underlying the prolific Cretaceous and Tertiary reservoirs in the Basra oilfields in southern Iraq. The study is based on well data of the Majnoon, West Qurna, Nahr Umr, Zubair, and Rumaila oil fields. Burial histories indicate complete maturation of Upper Jurassic source rocks during the Late Cretaceous to Paleogene followed by very recent (Neogene) maturation of the Low/Mid Cretaceous succession from early to mid-oil window conditions, consistent with the regional Iraq study of Pitman et al. (Geo Arab 9(4):41–72, 2004). These two main phases of hydrocarbon generation are synchronous with the main tectonic events and trap formation associated with Late Cretaceous closure of the neo-Tethys; the onset of continent–continent collision associated with the Zagros orogeny and Neogene opening of the Gulf of Suez/Red Sea. Palynofacies of the Lower Cretaceous Sulaiy and Lower Yamama Formations and of the Upper Jurassic Najmah/Naokelekan confirm their source rock potential, supported by pyrolysis data. To what extent the Upper Jurassic source rocks contributed to charge of the overlying Cretaceous reservoirs remains uncertain because of the Upper Jurassic Gotnia evaporite seal in between. The younger Cretaceous rocks do not contain source rocks nor were they buried deep enough for significant hydrocarbon generation.     

敏感性分析在烃源岩成熟度史模拟中的应用——以川东北地区普光5井古生界海相烃源岩为例

通过分析输人模型的参数对输出结果的影响,可以确定影响烃源岩成熟度史模拟的敏感性参数.本文应用Easy% Ro化学动力学模型,以普光5井为例,对川东北地区各期构造运动剥蚀厚度、古地表温度和古地温梯度进行了相关的敏感性分析.分析结果表明:研究区下寒武统、下志留统、下二叠统和上二叠统烃源岩现今成熟度状态完全受控于燕山运动晚幕...     

Geochemical characteristics of saturate hydrocarbons in crude oils and source rocks of the Qaidam, Tarim, Tupran basins, NW China

Based on the systematic analyses of fifteen typical crude oils and ten typical potential source rocks col-lected from the Qaidam,Tarim and Turpan basins,Northwest China,the geochemical characteristics of the oils and source rocks were investigated and oil-source rock correlations undertaken.The oils and source rocks deposited in saline lacustrine environment from the western Qaidam Basin were characterized by n-alkanes with even car-bon-number preference in the C20-C28 range,low pristane/phytane(Pr/Ph) ratios(less than 0.5),and high abundances of C27 steranes,gammacerane and C35 hopanes.The oils and source rocks deposited in marine environment from the Tarim Basin were characterized by n-alkanes with even carbon-number preference in the C14-C18 range,relatively low Pr/Ph ratios(near to 1),high abundance of C28 steranes,and relatively high gammacerane.In contrast,the oils and source rocks deposited in terrigenous bog environment from the Turpan Basin were characterized by relatively high Pr/Ph ratios(oil samples greater than 6) high abundance of C29 steranes,and relatively low gammacerane and C31-35 hopanes.The higher amounts of C37 and C38 n-alkanes of source rocks from the western Qaidam Basin and the Tarim Basin suggest an origin of these alkanes from functionalized C37 and C38 n-alkadienes and alkenones in prymnesiophytes living in lacustrine and marine environments.Oil-source rock correlations suggest oils in the west-ern Qaidam Basin were derived from the Oligocene Lower Ganchaigou Formation(E3),oils in the Tabei and Tazhong uplifts from the Tarim Basin have a genetic relationship with the Middle-Upper Ordovician source beds.Oils in the Turpan Basin generally fall into two genetic types.Most oils in the Taibei depression from the Turpan Basin were derived from the Lower-Middle Jurassic coal measures,but the fewer oils in this region are a mixed source derived from the Lower-Middle Jurassic coal measure and the Upper Permian source rocks.     

Characteristics and evaluation of Mesozoic source rocks in the southeastern East China Sea continental shelf

Source rocks are the material basis of oil and gas generation and determine the potential resources of exploration blocks and have important research value. This paper studies the lithology, thickness, and geochemistry of Mesozoic source rocks in the southeastern East China Sea continental shelf. The results show that the Mesozoic source rocks are mainly dark mudstone and coal-bearing strata. The total thickness of Lower–Middle Jurassic source rocks ranges from 100 m to 700 m, and that of Lower Cretaceous source rocks ranges from 50 m to 350 m. The overall thickness of Mesozoic source rocks is distributed in the NE direction and their thickness center is located in the Jilong Depression. The Lower–Middle Jurassic source rocks are mainly developed shallow marine dark mudstone and transitional coal measure strata. Those of the Lower Cretaceous are mainly mudstone of a fan delta front. Lower–Middle Jurassic and Lower Cretaceous hydrocarbon source rocks are dominated by type III kerogen, with Lower–Middle Jurassic hydrocarbon source rocks having high organic matter abundance and being medium–good hydrocarbon source rocks, while Lower Cretaceous hydrocarbon source rocks have relatively poor quality. From northwest to southeast, the vitrinite reflectance Ro of Mesozoic source rocks increases gradually. Source rocks in the study area are divided into three types. The first hydrocarbon-generating area is mainly located in the southeastern region of the study area, and the Jilong Depression is the hydrocarbon-generating center. The results of this study can provide a basis for exploration of Mesozoic oil and gas resources in the southeastern East China Sea continental shelf.© 2019 China Geology Editorial Office.