BIOMARKER CHARACTERISTICS OF CRUDE OILS FROM THE MURZUQ BASIN,SW LIBYA

Twenty crude oil samples from the Murzuq Basin, SW Libya (A‐, R‐ and I‐Fields in Blocks NC115 and NC186) have been investigated by a variety of organic geochemical methods. Based on biomarker distributions (e.g. n‐alkanes, isoprenoids, terpanes and steranes), the source of the oils is interpreted to be composed of mixed marine/terrigenous organic matter. The values of the Pr/Ph ratio (1.36–2.1), C₃₀‐diahopane / C₂₉ Ts ratio and diasterane / sterane ratio, together with the low values of the C₂₉/ C₃₀‐hopane ratio and the cross‐plot of the dibenzothiophene/phenanthrene ratio (DBT/P) versus Pr/Ph ratio in most of oil samples, suggest that the oils were sourced from marine clay‐rich sediments deposited in mild anoxic depositional environments. Assessment of thermal maturity based on phenanthrenes, aromatic steroids (e.g. monoaromatic (MA) and triaromatic (TA) steroid hydrocarbons), together with terpanes, and diasterane/sterane ratios, indicates that crude oils from A‐Field are at high levels of thermal maturity, while oils from Rand I‐Fields are at intermediate levels of thermal maturity. Based on the distributions of n‐alkanes and the absence of 25‐norhopanes in all of the crude oils analysed, none of the oils appear to have been biodegraded. Correlation of the crude oils points to a single genetic family and this is supported by the stable carbon isotope values. The oils can be divided into two sub‐families based on the differences in maturities, as shown in a Pr/nC₁₇ versus Ph/nC₁₈ cross‐plot. Sub‐family‐A is represented by the highly mature oils from A‐Field. Sub‐family‐B comprises the less mature oils from R‐ and I‐Fields. The two sub‐families may represent different source kitchens of different thermal maturity or different migration pathways. In summary, the geochemical characteristics of oil samples from A‐, R‐, and I‐Fields suggest that all the crude oils were generated from similar source rocks. Depositional environment conditions and advanced thermal maturities of these oils are consistent with previously published geochemical interpretations of the Rhuddanian “hot shale” in the Tanezzuft Formation, which is thought to be the main source rock in the Murzuq Basin.     

HYDROCARBON SOURCE ROCK POTENTIAL OF LATEST ORDOVICIAN – EARLIEST SILURIAN TANEZZUFT FORMATION SHALES FROM THE EASTERN KUFRA BASIN,SE LIBYA

This paper summarizes the results of Rock‐Eval pyrolysis data of 43 shale samples collected from the latest Ordovician – earliest Silurian (Tanezzuft Formation) interval in the CASP JA‐2 well at Jebel Asba on the eastern margin of the Kufra Basin, SE Libya. The results are supported by analysis of cuttings samples from an earlier well of uncertain origin nearby, referred to here as the UN‐REMSA well. The Tanezzuft Formation succession encountered in the JA‐2 well can be divided into three intervals based on Rock‐Eval pyrolysis data. Shales in the shallowest interval (20 – 46.5 m depth) are altered probably by weathering and lack significant amounts of organic matter. Total organic carbon (TOC) contents of shales from the intermediate interval (46.5 – 68.5 m depth) vary between 0.19 and 0.75 wt%. Most samples in this interval have very limited source rock potential although a few have Hydrogen Index (HI) values up to 378 mg S₂/g TOC. T_max values of 422 – 426°C indicate the organic matter is immature. Shales from the deepest interval (68.5 – 73.9 m depth) are diagenetically altered, perhaps by fluids flowing along a nearby fault or along the contact between the Tanezzuft Formation and the underlying Mamuniyat Formation and apparently lack any organic matter. Cuttings samples from the UN‐REMSA well have TOC contents of 0.48–0.87 wt%, HI values of 242–252 mg S₂/g TOC, and T_max values of 421–425°C. These results offer little support for the presence of the basal Silurian (Tanezzuft Formation) source rock which is prolific elsewhere in SW Libya and eastern Algeria and, together with the overall immaturity of the equivalent section, reduces the probability of finding major oil reserves in the eastern part of the Kufra Basin.     

ORGANIC GEOCHEMISTRY OF CRUDE OILS AND UPPER CRETACEOUS SOURCE ROCKS FROM CONCESSION 11, WEST SIRTE BASIN,LIBYA

This paper reports the results of Rock‐Eval pyrolysis and total organic carbon analysis of 46 core and cuttings samples from Upper Cretaceous potential source rocks from wells in the West Sirte Basin (Libya), together with stable carbon isotope (δ¹³C) and biomarker analyses of eight oil samples from the Paleocene – Eocene Farrud/Facha Members and of 14 source rock extracts. Oil samples were analysed for bulk (°API gravity and δ¹³C) properties and elemental (sulphur, nickel and vanadium) contents. Molecular compositions were analysed using liquid and gas chromatography, and quantitative biological marker investigations using gas chromatography – mass spectrometry for saturated hydrocarbon fractions, in order to classify the samples and to establish oil‐source correlations. Core and cuttings samples from the Upper Cretaceous Etel, Rachmat, Sirte and Kalash Formations have variable organic content and hydrocarbon generation potential. Based on organofacies variations, samples from the Sirte and Kalash Formations have the potential to generate oil and gas from Type II/III kerogen, whereas samples from the Etel and Rachmat Formations, and some of the Sirte Formation samples, have the potential to generate gas from the abundant Type III kerogen. Carbon isotope compositions for these samples suggest mixed marine and terrigenous organic matter in varying proportions. Consistent with this, the distribution of n‐alkanes, terpanes and steranes indicates source rock organofacies variations from Type II/III to III kerogen. The petroleum generation potential of these source rocks was controlled by variations in redox conditions during deposition together with variations in terrigenous organic matter input. Geochemical analyses suggest that all of the oil samples are of the same genetic type and originated from the same or similar source rock(s). Based on their bulk geochemical characteristics and biomarker compositions, the oil samples are interpreted to be derived from mixed aquatic algal/microbial and terrigenous organic matter. Weak salinity stratification and suboxic bottom‐water conditions which favoured the preservation of organic matter in the sediments are indicated by low sulphur contents and by low V/Ni and Pr/Ph ratios. The characteristics of the oils, including low Pr/Ph ratio, CPI ～l, similar ratios of C₂₇:C₂₈:C₂₉ ααα‐steranes, medium to high proportions of rearranged steranes, C₂₉ <C₃₀‐hopane, low Ts/Tm hopanes, low sulphur content and low V/Ni ratio, suggest a reducing depositional environment for the source rock, which was likely a marine shale. All of the oil samples show thermal maturity in the early phase of oil generation. Based on hierarchical cluster analysis of 16 source‐related biomarker and isotope ratios, four genetic groups of extracts and oils were defined. The relative concentrations of marine algal/microbial input and reducing conditions decrease in the order Group 4 > Group 3 > Group 2 > Group1. Oil – source rock correlation studies show that some of the Sirte and Kalash Formations extracts correlate with oils based on specific parameters such as DBT/P versus Pr/Ph, δ¹³C_saturates versus δ¹³C_aromatics, and gammacerane/hopane versus sterane/hopane.     

BIOMARKER GEOCHEMISTRY OF CRUDE OILS FROM THE QAIDAM BASIN, NW CHINA

A suite of 16 crude oil samples from 13 oilfields in the Qaidam Basin were analyzed using techniques including gas chromatography and gas chromatography - mass spectrometry. Biomarker compositions and parameters were used to investigate the palaeoenvironmental and depositional conditions and to correlate the oils with eachother. Oils from the western Qaidam Basin have pristane/phytane (Pr/Ph) ratios of less than 0.7, and contain abundant gammacerane, C₂₇ steranes, 4-methyl steranes and long-chain tricyclic terpanes. C₂₉ sterane 20S/(20S+20R) and ββ/(ββ+αα) ratios show that the western Qaidam oils have variable maturities ranging from immature to mature. Oils from the northern Qaidam Basin, by contrast, have Pr/Ph ratios greater than 3, low gammacerane contents, and relatively abundant C₂₉ steranes, bicyclic terpanes and alkylcyclohexanes. C₂₉ sterane 20S/(20S+20R) and ββ/(ββ+αα) ratios indicate that the northern Qaidam oils are mature.
δ¹³C values, which range from -25.4‰ to -28.3‰ with the exception of one oil from the north (-3l.6‰), are similar for oils from both the northern and western parts of the Qaidam Basin. The oils'carbon isotope compositions are similar to those of the organic matter in potential source rocks.
The western Qaidam oils are inferred to have originated from Tertiary source rocks deposited under anoxic and saline-hypersaline lacustrine conditions with dominant algal organic matter. The northern Qaidam oils are interpreted to be derived from Jurassic source rocks which were deposited in a freshwater lacustrine environment and which are dominated by terrigenous organic matter.     

GEOCHEMICAL CHARACTERISTICS OF CRUDE OILS FROM THE SHARARA-C OIL FIELD,MURZUQ BASIN,SOUTHWESTERN LIBYA

Crude oil samples from the Sharara-C oil field (Concession NC-115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC-MS), and gas chromatography – tandem mass spectrometry (GC-MS-MS) was used to analyse saturated biomarkers. The Sharara-C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age-specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation-related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation. Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material. The organic geochemical parameters determined for the Sharara-C crude oils were compared with published data on other crude oils from Concession NC-115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub-families in the Sharara oil field area which are genetically related but which have different maturities.     

DIAGENETIC EVOLUTION OF INCISED CHANNEL SANDSTONES: IMPLICATIONS FOR RESERVOIR CHARACTERISATION OF THE LOWER CARBONIFEROUS MARAR FORMATION, GHADAMES BASIN, WESTERN LIBYA

This paper assesses the diagenetic history of potential fluvial hydrocarbon reservoir rocks deposited within incised valley systems of the Lower Carboniferous Marar Formation in western Libya. Outcrop data were collected in the Tinedhan Anticline, located at the southern margin of the Ghadames Basin. Four discrete intervals with channelized sandstones were identified in a section dominated by alternating offshore mudstones and shallow-marine clastics. The incised channels were cut during major sea-level lowstands, and filled by fluvial sandstone packages up to 50 m thick. Fifty-eight samples from four different localities, representing three lowstand systems tracts, were analysed to obtain a statistically meaningful mineralogical and compositional dataset. In addition to burial compaction, three main diagenetic events influenced the reservoir quality of the sandstones. Firstly, early eodiagenesis involved kaolinitization of plagioclase grains. This began before subsequent calcite cementation, probably as a result of flushing by meteoric pore-waters. The deformation of kaolinite during later compaction resulted in the formation of pseudomatrix which further reduced porosity and permeability. Kaolinite is commonly transformed to illite at temperatures above 140°C in the presence of K-feldspar. Although K-feldspar was recorded in the samples, no illite was observed, suggesting that the Lower Carboniferous strata in the study area were not buried in excess of approximately 3.5 km. The second diagenetic phase was the precipitation of calcite cement, present either dispersed throughout the sandbodies or as concretions up to 2 m across, in both cases reducing reservoir quality. The high intergranular volumes (IGV) of calcite-cemented sandstones (ranging between 35% and 40%) suggest that cementation occurred at burial depths of <500 m. Sandstones without calcite cement have lower IGV of between 17% and 25% as a result of mechanical and chemical compaction. Stable C and O isotope analysis of the calcite cement also supports precipitation at shallow burial depths, indicating a meteoric pore-water source for the calcite. The third and final diagenetic stage was partial chloritisation of kaolinite during meso-diagenesis. The elevated temperatures required for this transformation indicate burial to a minimum depth of approximately 2.5 km, which is consistent with the compaction data. Despite these diagenetic effects, the fluvial sandstones have an average porosity of 12%, with a range from 0.5% up to 25%. Permeability measurements on four sandstone samples indicate that the development of pseudomatrix did not reduce permeability significantly.     

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of R_o = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (R_o 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.     

BIOMARKER GEOCHEMISTRY OF PALEOGENE CRUDE OILS AND SOURCE ROCKS FROM THE RAOYANG SAG,BOHAI BAY BASIN,NE CHINA: AN OIL – SOURCE ROCK CORRELATION STUDY

This study presents a systematic geochemical analysis of Paleogene crude oils and source rocks from the Raoyang Sag in the Jizhong sub-basin of the Bohai Bay Basin (NE China). The geochemical characteristics of fifty-three oil samples from wells in four sub-sags were analysed using gas chromatography (GC) and gas chromatography – mass spectrometry (GC-MS). Twenty core samples of mudstones from Members 1 and 3 of the Eocene-Oligocene Shahejie Formation were investigated for total organic carbon (TOC) content and by Rock-Eval pyrolysis and GC-MS to study their geochemistry and hydrocarbon generation potential. The oils were tentatively correlated to the source rocks. The results show that three groups of crude oils can be identified. Group I oils are characterized by high values of the gammacerane index and low values of the ratios of Pr/Ph, Ts/Tm, 20S/(20S+20R) C₂₉ steranes, ββ/(ββ+αα) C₂₉ steranes, C₂₇ diasteranes/ C₂₇ regular steranes and C₂₇/C₂₉ steranes. These oils have the lowest maturity and are interpreted to have originated from a source rock containing mixed organic matter deposited in an anoxic saline lacustrine environment. The biomarker parameter values of Group III oils are the opposite to those in Group I, and are interpreted to indicate a highly mature, terrigenous organic matter input into source rocks which were deposited in suboxic to anoxic freshwater lacustrine conditions. The parameter values of Group II oils are between those of the oils in Groups I and III, and are interpreted to indicate that the oils were generated from mixed organic matter in source rocks deposited in an anoxic brackish–saline or saline lacustrine environment. The results of the source rock analyses show that samples from Member 1 of the Shahejie Formation were deposited in an anoxic, brackish – saline or saline lacustrine environment with mixed organic matter input and are of low maturity. Source rocks in Member 3 of the Shahejie Formation were deposited in a suboxic to anoxic, brackish – saline or freshwater lacustrine environment with a terrigenous organic matter input and are of higher maturity. Correlation between rock samples and crude oils indicates that Group I oils were probably derived from Member 1 source rocks, while Group III oils were more likely generated by Member 3 source rocks. The Group II oils with transitional characteristics are likely to have a mixed source from both sets of source rocks.     

GEOCHEMISTRY AND ORIGIN OF CRUDE OILS AND CONDENSATES FROM THE CENTRAL PERSIAN GULF,OFFSHORE IRAN

Biomarker‐ and compound‐specific carbon isotope analyses were used to compare oil samples recovered from Late Jurassic and Early to Middle Cretaceous reservoirs at South Pars and nearby fields in the Iranian portion of the Persian Gulf, and condensate samples associated with the super‐giant gas accumulation in Permo‐Triassic reservoirs at South Pars. The results indicate that all of the oil samples, including heavy oil from South Pars and oil from the Salman, Reshadat, Resalat and Balal fields, are genetically related. The most probable source rocks for these oils are Jurassic marine limestones or marls deposited under anoxic conditions. Based on the methyl phenanthrene index, source rock maturity was inferred to be equivalent to vitrinite reflectance values of about 0.8% Rc. The distribution and maturity pattern of the source rocks suggest migration from a depocentre located to the south, with inferred migration distances of up to 250 km. There is no genetic relationship between the heavy oil which has accumulated in Mesozoic reservoirs at South Pars and condensates which are associated with the super‐giant gas accumulation in Permo‐Triassic reservoirs there. Based on biomarker compositions, the condensates at South Pars appear to be derived from shaly marine or lacustrine source rocks deposited under dysoxic conditions. The δ¹³C values of short‐chain n‐alkanes and isoprenoids in condensate samples suggest a common source and an equal maturity for the source rocks. Pristane/n‐C₁₇ versus phytane/n‐C₁₈ characteristics are in agreement with published data for Silurian‐sourced condensates. High thermal maturities equivalent to 1.7% Rc are also consistent with a Palaeozoic (Silurian) source rock.     

ORGANIC GEOCHEMISTRY OF POTENTIAL SOURCE ROCKS IN THE TERTIARY DINGQINGHU FORMATION,NIMA BASIN,CENTRAL TIBET

The Tertiary Nima Basin in central Tibet covers an area of some 3000 km² and is closely similar to the nearby Lunpola Basin from which commercial volumes of oil have been produced. In this paper, we report on the source rock potential of the Oligocene Dingqinghu Formation from measured outcrop sections on the southern and northern margins of the Nima Basin. In the south of the Nima Basin, potential source rocks in the Dingqinghu Formation comprise dark‐coloured marls with total organic carbon (TOC) contents of up to 4.3 wt % and Hydrogen Index values (HI) up to 849 mg HC/g TOC. The organic matter is mainly composed of amorphous sapropelinite corresponding to Type I kerogen. Rock‐Eval T_max (430–451°C) and vitrinite reflectance (R_r) (average R_r= 0.50%) show that the organic matter is marginally mature. The potential yield (up to 36.95 mg HC/g rock) and a plot of S2 versus TOC suggest that the marls have moderate to good source rock potential. They are interpreted to have been deposited in a stratified palaeolake with occasionally anoxic and hypersaline conditions, and the source of the organic matter was dominated by algae as indicated by biomarker analyses. Potential source rocks from the north of the basin comprise dark shales and marls with a TOC content averaging 9.7 wt % and HI values up to 389 mg HC/g TOC. Organic matter consists mainly of amorphous sapropelinite and vitrinite with minor sporinite, corresponding to Type II‐III kerogen. This is consistent with the kerogen type suggested by cross‐plots of HI versus T_max and H/C versus O/C. The T_max and R_r results indicate that the samples are immature to marginally mature. These source rocks, interpreted to have been deposited under oxic conditions with a dominant input of terrigenous organic matter, have moderate petroleum potential. The Dingqinghu Formation in the Nima Basin therefore has some promise in terms of future exploration potential.     

GEOCHEMISTRY AND ORIGIN OF UPPER CRETACEOUS OILS FROM THE TERMIT BASIN,NIGER

Crude oil samples (n = 16) from Upper Cretaceous reservoir rocks together with cuttings samples of Upper Cretaceous and Paleogene mudstone source rocks (n = 12) from wells in the Termit Basin were characterized by a variety of biomarker parameters using GC and GC‐MS techniques. Organic geochemical analyses of source rock samples from the Upper Cretaceous Yogou Formation demonstrate poor to excellent hydrocarbon generation potential; the samples are characterized by Type II kerogen grading to mixed Types II–III and III kerogen. The oil samples have pristane/phytane (Pr/Ph) ratios ranging from 0.73 to 1.27, low C₂₂/C₂₁ and high C₂₄/C₂₃ tricyclic terpane ratios, and values of the gammacerane index (gammacerane/C₃₀hopane) of 0.29–0.49, suggesting derivation from carbonate‐poor source rocks deposited under suboxic to anoxic and moderate to high salinity conditions. Relatively high C₂₉ sterane concentrations with C₂₉/C₂₇ sterane ratios ranging from 2.18–3.93 and low values of the regular steranes/17α(H)‐hopanes ratio suggest that the oils were mainly derived from kerogen dominated by terrigenous higher plant material. Both aromatic maturity parameters (MPI‐1, MPI‐2 and R_c) and C₂₉ sterane parameters (20S/(20S+20R) and ββ/ (αα + ββ)) suggest that the oils are early‐mature to mature. Oil‐to‐oil correlations suggest that the Upper Cretaceous oils belongs to the same genetic family. Parameters including the Pr/Ph ratio, gammacerane index and C₂₆/C₂₅ tricyclic terpanes, and similar positions on a sterane ternary plot, suggest that the Upper Cretaceous oils originated from Upper Cretaceous source rocks rather than from Paleogene source rocks. The Yogou Formation can therefore be considered as an effective source rock.     

BIOMARKER CHARACTERISTICS OF POTENTIAL SOURCE ROCKS IN THE JABAL NAFUSAH AREA,NW LIBYA: PETROLEUM SYSTEMS SIGNIFICANCE

The Jifarah Arch of NW Libya is a structurally prominent feature at the eastern end of the regional Talemzane Arch, separating the Ghadamis hydrocarbon province to the south from the offshore Pelagian province to the north. The Arch has experienced a complex structural history with repeated episodes of uplift, exhumation and burial. This paper provides a provisional assessment of its hydrocarbon habitat based on detailed geochemical analyses of potential Triassic, Silurian and Ordovician source rocks encountered by wells drilled in the area. Twenty‐seven core and cuttings samples of marine shales were collected from eight widely‐ dispersed wells and analyzed using standard Rock‐Eval pyrolysis techniques. Kerogen types II‐III were identified in the majority of Triassic samples analysed, indicating a low hydrocarbon generation potential, but oil‐prone Type II kerogen was found in the basal Silurian Tanezzuft Formation and Ordovician Memouniat Formation. The presence of steranes and acyclic isoprenoids suggested variable inputs of algal, bacterial and terrestrial organic matter, while biomarkers including C₃₀‐gammacerane and β–carotene and selected biomarker ratios (Pr/Ph ratio and homohopane index) were used to assess their depositional environment. Results indicate that extended zones with periodic (if not continuous) oxygen‐deficient conditions existed throughout the basin during Late Ordovician and Early Silurian time, favouring the preservation of organic matter. The thermal maturity of the samples was assessed by Rock‐Eval pyrolysis, zooclast reflectance, molecular ratios including C_32‐22S/(22S+22R)‐homohopanes, Ts/(Ts+Tm), C₂₉‐steranes and parameters based on the relative abundance of methylphenanthrene, methyldibenzothiophene and methylnaphthalene isomers. The results indicate significant variability in thermal maturity, with Ordovician and Silurian source rocks ranging from 0.6% to 0.7% VR_o equivalent increasing to 1.0% locally. These values represent palaeo‐maturities achieved at different times in the past and are considered too low to have generated significant volumes of hydrocarbons directly. However the downdip equivalents of these source rocks in the adjacent Ghadamis Basin contributed to prolific petroleum systems. The absence of large petroleum accumulations on the Jifarah Arch contrasts with the western part of the geologically similar Talemzane Arch, which harbours several giant and supergiant oil and gas fields. This difference is attributed both to the complex structural history of the Jifarah Arch, which permitted post‐charge leakage of palaeo‐accumulations, and stratigraphic migration barriers which restricted migration between Tanezzuft source rocks and Ordovician and Triassic reservoirs.     

MATURITY AND SOURCE-ROCK POTENTIAL OF MESOZOIC AND PALAEOZOIC SEDIMENTS, JIFARAH BASIN, NW LIBYA

The Jifarah Basin, NW Libya, has a sedimentary fill which includes marine shales of Triassic, Permian, Silurian and Ordovician ages together with Jurassic evaporites and Cambro-Ordovician aeolian sandstones. Major risk in exploration of the basin is associated with the presence of source rocks. The present study investigates potential source rocks in the basin and assesses their thermal maturity, petroleum generation potential, organic richness and distribution. Cuttings and core samples from nine wells were analyzed using a Rock-Eval 6 instrument and by standard petrographic microscopy. Kerogen type and amount were recorded.
Triassic and Ordovician formations were only drilled in parts of the basin and have minor petroleum generation potential. Permian and Devonian samples also had low generation potential, as did samples from the upper part of the Silurian. The Devonian succession is of limited extent as a result of Hercynian uplift and erosion.
Major petroleum generation potential is associated with the lower part of the Silurian Tanezzuft Formation in which high TOC values and moderate to high HI values were recorded. The formation is characterized by abundant fluorescing alginite. Most samples studied were early mature to mid-mature but there was some regional variability.     

羌塘盆地羌资2井布曲组碳酸盐岩生物标志物特征及意义

首次报道了藏北羌塘盆地羌资2井中侏罗统布曲组海相碳酸盐岩生物标志化合物特征,该层位含有丰富的正烷烃、类异戊二烯烷烃和萜甾类化合物。正烷烃形态为单峰和双峰并存、以单峰形态占优势,主碳峰以nC₁₇,nC₂₀为主,次为nC₁₈,nC₁₅,nC₁₆,轻烃组分占有绝对优势;OEP值介于0.37~1.14之间,平均值为0.89,无明显的奇偶优势分布;Pr/Ph值介于0.56~1.03之间,平均值为0.75,具有明显的植烷优势。萜烷相对丰度为五环三萜烷>三环萜烷>四环萜烷,伽马蜡烷普遍存在,但相对含量较低;甾烷主要为规则甾烷,少量孕甾烷,规则甾烷∑(C₂₇+C₂₈)>∑C₂₉,∑C₂₇/∑C₂₉介于0.67~1.22之间,显示弱的C₂₇甾烷优势或弱的C₂₉甾烷优势。有机质母质主要来源于藻类等低等水生生物,不能确定是否有陆生高等植物输入。成熟度参数和镜质体反射率均显示碳酸盐岩处于成熟阶段。碳酸盐岩沉积环境总体为缺氧还原—弱还原的海相环境,海水盐度基本正常。     

朝鲜安州盆地原油地球化学特征

安州盆地是朝鲜最大的中新生界陆相含油气沉积盆地.对始新统和下白垩统产层原油的有机地球化学研究表明:始新统原油具有煤成油的主要地化特征,源岩可能为如新统煤系地层;下白垩统原油具有湖相原油一般特征,与朝鲜湾盆地侏罗系原油及株罗系湖相源岩有一致性.安州盆地存在不同类型的油源岩和原油,具有一定的油气勘探远景.     

柴达木盆地原油烃类地球化学特征

柴达木盆地是我国重要的中新生代含油气盆地。已发现的18个油田分布于柴北地区和柴西地区,且以柴西地区最多。两个地区原油的成因截然不同,引起了国内外学者的关注。对采集于两地区13个油田的16个原油样品中烃类生物标志化合物进行了系统的分析,研究了它们的地球化学特征。生物标志化合物的分布和组成特征指示了西部原油形成于强还原咸水—超咸水湖相,北部原油形成于弱氧化淡水湖沼相;西部原油的母质主要为菌藻类,北部原油更多的来自陆源高等植物。根据生物标志化合物特征,并结合碳同位素组成,将柴达木盆地原油划分为两大类7种次级成因类型。     

塔里木盆地台盆区志留系层序划分及其特征

层序地层学是 1 977年由美国Rice大学的Vail教授及其Exxon公司的同行们在地震地层学基础上发展起来的。从 2 0世纪 80末期 ,国内外开始掀起层序地层学研究热潮 ,它在石油勘探中具有相当的实用性。在前人划分的基础上 ,把塔里木盆地台盆区志留系地层划分为 6个层序。在所划分的这些层序中第一层序为Ⅰ型层序 ,其余层序为Ⅱ型层序。第一层序由低位体系域、海侵和高位体系域三部分组成 ,而其余 5个层序均由海侵体系域和高位体系域两部分组成     

ORGANIC GEOCHEMISTRY,BURIAL HISTORY AND HYDROCARBON GENERATION MODELLING OF THE UPPER JURASSIC MADBI FORMATION,MASILA BASIN,YEMEN

The Masila Basin is an important hydrocarbon province in Yemen but the origin of its hydrocarbons is not fully understood. In this study, we evaluate Upper Jurassic source rocks in the Madbi Formation and assess the results of basin modelling in order to improve our understanding of burial history and hydrocarbon generation. This source rock has generated commercial volumes of hydrocarbons which migrated into Jurassic and Lower Cretaceous reservoir rocks. Cuttings samples of shales from the Upper Jurassic Madbi Formation from boreholes in the centre-west of the Masila Basin were analysed using organic geochemistry (Rock-Eval pyrolysis, extract analysis) and organic petrology. The shales generally contain more than 2.0 wt % TOC and have very good to excellent hydrocarbon potential. Kerogen is predominantly algal Type II with minor Type I. Thermal maturity of the organic matter is R_r 0.69–0.91%. Thermal and burial history models indicate that the Madbi Formation source rock entered the early-mature to mature stage in the Late Cretaceous to Early Tertiary. Hydrocarbon generation began in the Late Cretaceous, reaching maximum rates during the Early Tertiary. Cretaceous subsidence had only a minor influence on source rock maturation and OM transformation.     

UPPER TRIASSIC POTENTIAL SOURCE ROCKS IN THE QIANGTANG BASIN,TIBET: ORGANIC GEOCHEMICAL CHARACTERISTICS

Upper Triassic coal‐bearing strata in the Qiangtang Basin (Tibet) are known to have source rock potential. For this study, the organic geochemical characteristics of mudstones and calcareous shales in the Upper Triassic Tumengela and Zangxiahe Formations were investigated to reconstruct depositional settings and to assess hydrocarbon potential. Outcrop samples of the Tumengela and Zangxiahe Formations from four locations in the Qiangtang Basin were analysed. The locations were Xiaochaka in the southern Qiangtang depression, and Woruo Mountain, Quemo Co and Zangxiahe in the northern Qiangtang depression. At Quemo Co in the NE of the basin, calcareous shale samples from the Tumengela Formation have total organic carbon (TOC) contents of up to 1.66 wt.%, chloroform bitumen A contents of up to 734 ppm, and a hydrocarbon generation capacity (Rock‐Eval S₁+ S₂) of up to 1.94 mg/g. The shales have moderate to good source rock potential. Vitrinite reflectance (R_r) values of 1.30% to 1.46%, and Rock‐Eval T_max values of 464 to 475 °C indicate that the organic matter is at a highly mature stage corresponding to condensate / wet gas generation. The shales contain Type II kerogen, and have low carbon number molecular compositions with relatively high C_21?/C₂₁₊ (2.15–2.93), Pr/Ph ratios of 1.40–1.72, high S/C ratios (>0.04) in some samples, abundant gammacerane (GI of 0.50–2.04) and a predominance of C₂₇ steranes, indicating shallow‐marine sub‐anoxic and hypersaline depositional conditions with some input of terrestrial organic matter. Tumengela and Zangxiahe Formation mudstone samples from Xiaochaka in the southern Qiangtang depression, and from Woruo Mountain and Zangxiahe in the northern depression, have low contents of marine organic matter (Type II kerogen), indicating relatively poor hydrocarbon generation potential. R_r values and T_max data indicate that the organic matter is overmature corresponding to dry gas generation.     

渤海湾盆地东营凹陷孔店组烃源岩特征研究

沙三下和沙四上是东营凹陷的2套优质烃源岩。目前认为东营凹陷南斜坡原油主要属于“沙四型”,而对于东营凹陷孔店组的生烃潜力一直存在着争论。油源对比结果表明,孔店组烃源岩以较高的伽马蜡烷区别于沙三型烃源岩,又以较高的三升藿烷和C₂₉甾烷S构型区别于沙四型烃源岩;南斜坡孔店组及其以下的深层原油与孔店组烃源岩具有亲缘关系。虽然目前发现的孔店组烃源岩有机质含量较低、类型差、成熟度较高,综合评价较差,但是生物标志化合物显示,向沉积中心其有机质有优化的趋势。因此推测在沉积中心发育更优质的孔店组烃源岩,其生烃潜力不容忽视。