C29 Steranes Research Articles

Organic Geochemical Characteristics of Mudstone and Marl from Western Hoh Xil Basin of Tibet

The mudstone and marl from western Hoh Xil basin, located in Tibet of the west of China, were deposited in Tertiary lacustrine environment. Investigation of organic geochemistry, sedimentary characteristics, and 13C in kerogen was conducted to analyze the sedimentary environment, biomarkers, paleoclimate, and source of organic matter during deposition. The Cenozoic sedimentary facies of the basin included upper lacustrine facies and lower alluvial fan facies, which belong to Miocene Wudaoliang Formation and Oligocene Yaxicuo Group, respectively. The Miocene marl-sandstone-mudstone from Wudaoliang Formation was analyzed. Maceral composition was dominated by amorphous organic matter. T max values indicated that the mudstones were thermally immature-low maturity with mainly type II and III organic matter, while organic matter in marlite belongs mainly to type I-II1 with low maturity-maturity stage. The biomarkers showed the characteristics of odd-over-even predominance of long-chain n-alkanes, higher proportion of C27 sterane in most of the samples, heavy δ13Corg composition, low Pr/Ph ratios (0.11-0.36), and so on. Organic geochemistry indicated that the organic matter originated from bacteria, algae, and higher plants. The rocks were formed in reducing environments with stratified water column and high productivity. The paleoclimate became more humid during depositional stage in the western Hoh Xil basin.

Source rock characterization and oil grouping in the NW Java, Central Java and NE Java Basins, Indonesia

This study reveals the detailed organic geochemistry from crude oils (acquired from wells and seepages) and rock extracts from NW Java and NE Java Basin that have been gathered and compiled from previous publications. The interpretation was conducted from geochemical data value and plot, GC-MS fingerprints, and agglomerative-hierarchical cluster analysis using the Euclidean algorithm. Various source rocks from those basins were deposited under fluvio-lacustrine to the marine environment. Six groups of crude oils are also distinguished. Groups 1, 2, and 6 are oils from deltaic source rocks, Groups 3 and 4 are oils from marine source rocks, and Group 5 is from lacustrine and/or fluvio-lacustrine source rocks. Groups 1, 2, and 6 could be distinguished from the pristane/phytane (Pr/Ph) ratio and C29 sterane composition, while Groups 3 and 4 differ from the distribution of C27 sterane. The schematic depositional environment of source rocks is also generated from this study and suggests that Group 5 is deposited during early syn-rift non-marine settings, while the remaining groups are deposited in the deltaic (Group 1,2 and 6) and marine settings (Groups 3 and 4). The main differences between those groups are including the distributions of C27-C28-C29 steranes.

A distinct oil group in the Dongying Depression, Bohai Bay Basin, China: New insights from norcholestane and triaromatic steroid analyses

The lower third and upper fourth members of the Eocene Shahejie Formation (lower Es3 and upper Es4) are known as two sets of effective source rocks in the Dongying Depression, Bohai Bay Basin. In this study, the saturated and aromatic steroids of 20 crude oil samples from the Dongying Depression were systematically investigated using gas chromatography–mass spectrometry (GC–MS) and GC–MS metastable reaction monitoring. Based on the distribution patterns of the steranes, norcholestanes, and triaromatic steroids, the Group I and II oils were clearly identified and shown to be derived from the lower Es3 and upper Es4 source rocks, respectively. Significantly, it was discovered that three oil samples collected from the Eocene Kongdian Formation and the Ordovician reservoirs exhibit completely different steroid and isotopic compositions from those of the Group I and II oils. These oils, as a distinct oil group (Group III), have the characteristics of abnormally high concentrations of C29 steranes, 24-nordiacholestane, 27-nordiacholestane, C28 triaromatic steroids, C27 4α-methyltriaromatic steroids, and C29 4α-methyl-24-ethyltriaromatic steroids, and low concentrations of 24-norcholestane, 27-norcholestane and triaromatic dinosteroids, and 13C depletion. Although the related source rock of Group III oils needs to be further clarified in the study area, the 13C depletion, abundant C29 steranes, and low 24-norcholestane content may suggest greater bacteria/algae inputs (e.g., green algae rather than dinoflagellates) than both the lower Es3 and upper Es4 source rocks. Identification of the Group III oils indicates that the norcholestanes and triaromatic steroids may be more effective molecular fossils for the classification of crude oils in complicated petroleum exploration fields.

Organic Geochemistry of Peat Deposits in southwest Rwanda

Rwanda hosts million tons of peat deposits and that of western province is of great importance as it close to Kivu Lake. The discovery of methane gas in Kivu Lake has attracted investors in methane gas utilization as source of power supply and Compressed Natural Gas (CNG). Researchers identified Kivu Lake and adjacent area as an area of interest for hydrocarbon exploration. However, organic geochemical prospecting for hydrocarbon and energy content assessment is inadequate for the identified areas. The study aimed at determining the organic geochemistry of peat deposits in southwest, Rwanda. Forty (40) subsurface peat samples (1 to 10 m depth) were collected, air-dried and pulverized and screened. Five (5) samples with high organic matter content were subjected to biomarkers analysis using GC-GCMS. The n-alkanes distribution comprised mainly n-C11 to n-C 37. The Pr/Ph ratios (3.3-10.4, the waxiness index (0.09-0.87), CPI (3.6-7.8), OEP (3.5-6.0), C29 steranes (63.0–100.0%), C28 (0.0–28.0%), C27 (0.0–18.0%) and C27/ C29 sterane ratios (0.0-0.28). The ββ/ (ββ + αα) and 20S/ (20S + 20R) are 0.5 and 0.46 respectively. The C30 -moretane/ C30 -hopane ratios ranged from 1.56 to 2.42, while the oleanane index ranged from 0.07 to 0.26. The Ts/ (Ts + Tm) ratios ranged from 0.13 to 1.05. The dominance of C-29 sterols and C29/C27 sterane ratio which ranged from 3.5 to 100 indicating derivation from terrigenous higher plant material. The Pr/Ph ratio (>3) reflect the oxic to sub-oxic environmental condition during peat deposition. The peat deposits in Western Province, Rwanda are very rich in organic matter of mainly terrestrial precursor deposited in dry and cold climate.

The origin and source of heavy oil and its control on oil and gas accumulation

ABSTRACT A large amount of heavy oil have been found in the eastern section of Dinan uplift, Junggar basin. Previous studies on heavy oil mainly focused on the origin and source, and few studies have been conducted on the influence of heavy oil on reservoir physical properties and the control of oil and gas enrichment. Based on this, through the analysis of oil and gas geochemical characteristics and the comparison of reservoir physical properties before and after oil washing, the genesis of heavy oil in this area and the control effect of heavy oil on oil and gas accumulation are systematically studied. The results show that: (1) The carbon isotope of crude oil in this area is lower than −30‰, Pr/Ph is less than 2, C28 and C29 sterane content is high, which is a typical Permian source rock product. (2) Due to the incompleteness of saturated hydrocarbon chromatogram, low maturity of heavy oil isassociated with bacterial decomposition gas, which indicates that the heavy oil is formed by biodegradation of early products of Permian source rock. (3) Heavy oil fills the pores and fractures of the reservoir and occupies a large number of pores and throats, which affects the physical properties and pore structure. After the heavy oil was dissolved, the average increase in sample porosity and permeability is 3.79% and 0.435 × 10−3μm2. (4) The heavy oil formed in the high part of the structure has a certain plugging effect on the reservoir, which leads to the high mature oil and gas in the deep part of the depression did not migrate to the high part of the structure to form an oil reservoir. Therefore, the next step of the exploration for products in the high maturity stage of the depression should be extended to the depression slope area.

Paleoenvironment and origin of heavy oil of the lower Cretaceous-Oligocene: a case study

ABSTRACT Many heavy oil wells have been found in the Jilantai shallow depression in the Hetao Basin. The origin of heavy oil in the study area was analyzed comprehensively according to the physical properties and geochemical characteristics of heavy oil. Two sets of source rocks were detected in the Guyang and Linhe groups, in the Hetao Basin. During the Guyang Formation, the differences of sedimentary environments resulted in brackish water sedimentary environment in the south of the study area and freshwater reducing environment in the north of the study area. The high content of boron in the source rocks of Linhe Formation indicates its saltwater environment. By the method of oil source comparison, it is found that the Pr/Ph of the crude oil in Jilantai area and Linhe Formation is lower than 0.50, and the Pr/nC17 is between 0.7 and 3.5, which should come from the source rock of the first segment of the southern moderate lacustrine Guyang Formation. The C29 sterane 20S/(20S+20 R) and C29 sterane ββ/(αα+ββ) parameters indicate that the low maturity of crude oil is the main cause of heavy oil formation. The research on the genesis and geochemical characteristics of Jilantai crude oil indicates that the northern and central depression of the Hetao Basin is a rich area of favorable resources.

Biotic response to environmental shift during the Permian-Triassic transition: Assessment from organic geochemical proxies and palynomorphs in terrestrial sediments from Raniganj Sub-basin, India

The Permian-Triassic (P/T) mass extinction qualifies as the severest biotic perturbation in the history of our planet. Biomarkers, stable isotopes and palynomorphs are excellent proxies offering glimpses into palaeobiota and past ecosystems. These were investigated from coal-bearing upper Permian (Raniganj Formation) and Lower Triassic (Panchet Formation) Gondwana sediments recovered from the Raniganj Sub-basin, eastern India. The geochemical and palaeobotanical data suggest a shift in the terrestrial vegetation during the Early Triassic. A distinct change occurs from high abundance of n-C23 and n-C25 alkanes and higher CPI values in the upper Permian sediments to predominantly n-C27 and n-C29 alkanes along with relatively lower CPI values in the Lower Triassic. A sharp decline of the diterpenoid compounds and Glossopteridales pollens with a concomitant rise in lycopsid spores in the Lower Triassic sediments reflects the waning of a gymnosperm-dominated mire and onset of a stressed environment. Unlike the Glossopteridales, the Coniferales appear to be a resilient floral group with several new genera adapting to the growing arid conditions in the Early Triassic. The microbial community also responded to the contemporaneous ecosystem shift, with higher concentration of C27 sterane relative to C29 sterane in Lower Triassic sediments indicating proliferation of algal phytoplankton. The decreasing moretane/hopane (M/H) suggests that the soil bacteria were adversely affected plausibly due to enhanced soil erosion at the early part of the Triassic. A marked shift in the bulk isotopic composition (δ13Corg) from higher values in the upper Permian sediments (˗21.0 to ˗24.1‰) to lower values in the Lower Triassic sediments (˗21.2 to ˗32.5‰) is diagnostic of a vegetation changeover as a result of environmental deterioration. This is the first integrated study using molecular organic geochemical proxies and palynology from terrestrial Gondwana sediments in the Indian subcontinent, designed to investigate the pattern of floral and microbial restructuring as a result of an environmental shift during the Permian-Triassic transition.

Geochemical characteristics, provenance and paleodepostional environment of the Lower Jurassic Huxishan Formation in the Lenghu area, northwestern Qaidam Basin, North West China: Implications for organic matter origin

The organic-rich mudstone of Lower Jurassic Huxishan Formation (J1h) in the Lenghu area is the main oil prone source rocks in the northwestern Qaidam Basin. However, the evolution of dispositional environment and the provenance of dispositional rocks and organic matter are still unclear. Based on the data of element contents, total organic carbon and biomarkers of 143 samples, this study aims to investigate the provenance, paleoclimate, paleowater environment and origin of organic matter. The samples show high contents of terrigenous elements Ti, Sc, La and Co. Moreover, the Ti/Zr–La/Sc, La–Th–Sc, SiO2–K2O/Na2O and K2O/Na2O–SiO2/Al2O3 discrimination diagrams indicate that the tectonic settings of the provenance are oceanic island arc and continental island arc. Weight ratios of Ti/Zr, La/Sc and Th/Co of the J1h samples show values of 6.86–204.08, 0.19–2.16 and 0.015–0.123, which demonstrate a common source of clasts from mafic rocks. The Co/Th–La/Sc and La/Th–Hf discrimination diagrams also indicate that the provenance is mafic rocks with background of oceanic island arc, suggests that the provenance came from different stages in the subduction of the regional ocean and land in the Early Paleozoic. The weathering indices suggest that the samples faced moderate to intense weathering, combining with climate indices, illustrate that the paleoclimate was warm and humid, and the precipitation showed an increased trend from bottom to top. The values of CaO/MgO·Al2O3 show a decreased trend, implying that the paleotemperature had a decreased trend and the average annual temperature was less than 14.2 °C. The values of Sr/Ba, Rb/K and discrimination diagram of Pr/nC17–Ph/nC18–Pr/Ph indicate that the paleowater was predominantly fresh water with occasional brackish and salt water, which also provide evidence of lower salinity of water within the lower strata and increased salinity (fresh water to salt water) within the middle and upper of the strata. The values of V/(V + Ni), V/Cr, U/Th and Pr/Ph indicate that the samples mainly deposits in weak to moderate reducing environment. The reduction degree decreased first and then increased from bottom to top with a few oxidation sections are distributed in the middle of the formation, which indicate a process of lake regression and transgression. The paleoproductivity during organic-rich mudstone sedimentation was high in terms of P/Ti, Cu + Ni + Zn and TOC (1.99%–22.59%), which have a positive trend with paleosalinity. This indicates that the water with higher salinity is more active in nutrient supply. The productivity from large to small is the middle section, the upper section and the lower section, respectively. The homologous series of C27, C28 and C29 regular steranes, main carbon number perks, maximum carbon number, Ph/nC18–Pr/nC17 and ∑nC21-/∑nC22+ all indicate that the source of the organic matter during the J1h organic-rich mudstone was mainly terrestrial higher plants, the proportion of algae and phytoplankton increased in the upper section. The results show that the organic-rich mudstones of the Huxishan Formation developed under the background of lake regression and lake transgression. The dispositional environment and organic types of huxishan formation are obviously different in different sections.

Biomarker Geochemical Evaluation of Organic Rich Shales in Mamfe Basin, Cameroon

The Mamfe Basin is an intra-continental basin in southwestern Cameroon. Shale from Cretaceous strata in the Mamfe Formation has been poorly characterized in terms of their palaeo-environmental conditions and origin of the organic matter. Also, the thermal maturity of the shale has not been well established. The aim of this study is to determine the origin of the organic matter, evaluate the thermal maturity, palaeo-environmental conditions, and thereby deduce their hydrocarbon generative potential. Biomarker geochemical analyses was carried out on the organic matter extracts of some selected shale samples from Mamfe Formation having total organic carbon content ranging from 0.69 and 4.50 wt. % (av. =1.82 wt. %). Base on the total organic carbon content, the shales are described to have good hydrocarbon generative potentials. Thermal maturity parameters base on 20S/(20S +20R), and ββ/(ββ + αα) C29 sterane ratios along with CPI and OED indicate that the analysed samples from Mamfe Formation sit at mature oil window generation. The origin of the organic matter have been deduced to be mainly of terrestrial plant source with minor lacustrine and marine influences. Palaeo-environmental conditions were decipher to be of sub-oxic to anoxic conditions that have preserved the organic matter. This study have highlight valuable insight based on the biomarker geochemistry of the shales of the Mamfe Basin thereby reducing petroleum exploration risk.

Biomarker and Carbon Isotopic Evidence of Marine Incursions in the Himalayan Foreland Basin During Its Overfilled Stage

AbstractThe final stages of evolution of the Himalayan foreland basin (HFB) are preserved in the Siwalik Group of rocks deposited by meandering and/or braided rivers in the western and central regions of HFB. However, the time‐equivalent deposits in the eastern part of the foreland provide contradictory evidence of both terrestrial and marine environments. To address the ambiguity, molecular level characterization and stable isotopic composition of organic matter (OM) have been employed in the late Miocene‐Pliocene sequence of the eastern HFB. The n‐alkane distribution, carbon isotopic (δ13C) signature of n‐alkanes and distribution of hopane and sterane isomers suggest OM contributions from both marine and terrestrial sources during the late Miocene period. Increase in short‐chain n‐alkane abundance and gammacerane index, low pristane/phytane ratio, higher δ13C values, higher regular sterane/17α‐hopane, C31R/C30‐hopane and C27/C29 steranes ratios and presence of C30 sterane provides substantial evidence of stratified anoxic conditions and marine influences at specific stratigraphic intervals. During the late Miocene period, mixing of marine OM sources with terrestrial sources argue for marginal marine depositional conditions amid fluvial‐dominating environments. The entry of marine waters in the eastern HFB through the pre‐existing cratonic troughs possibly resulted from eustatic or relative sea‐level rise. No further evidence of marine incursions is observed in the younger Pliocene sediments. The higher detrital influx from the rising Himalayas, the onset of Northern Hemisphere Glaciation and evolution of physical barriers such as Shillong Massifs and Barind Tracts altogether led to the cessation of marine incursions into the HFB.

Molecular markers of Neoproterozoic-Lower Paleozoic petroleum systems and their geological significance: A case study of the cratonic basins in western China

In this article, we report the investigation of the Ediacaran and Lower Paleozoic petroleum systems using their molecular markers. The cratonic basins located in western China were selected as a case study, whereas worldwide published samples where compiled for comparison. The study aimed in characterizing specifically and generally the molecular markers, and providing their geological significance as well. Gas chromatography-mass spectrometry experiments (GC-MS) were applied on Ediacaran reservoir solid bitumen extracts (Dengying Formation, member-Z2dn2) and Cambrian oil/rock extracts samples respectively from Sichuan Basin and Tarim Basin. The results show a predominance of n-alkanes over isoprenoids (e.g. Pr/nC17, Ph/nC18), a noticeable absence of 25-norhopane and monoaromatic steroids among all the samples. The values of pristane to phytane ratio (Pr/Ph) fall below 0.8 for all the solid bitumen samples, whereas they are equal to 0.9, on average, for the Lower-Middle Cambrian oils and rock extracts. Relatively high values of gammacerane to C30 17α (H)-hopane ratio (G/C30H), low values of C30 17α (H)-diahopane/C30H (average = 0.09), and a V-shaped distribution pattern for the following C29–C28–C27 regular steranes with C27 > C29 > C28 and C28 < C27 < C29 respectively for Ediacaran and Cambrian samples, have been noticed as well. Moreover, the values of the following ratios: ββ/(ββ+αα) and 20S/(20S + 20R) C29 steranes, tricyclic terpanes/(tricyclic terpanes +17α-hopanes), and Ts/(Ts + Tm) fall below their respective equilibrium endpoints, notwithstanding the calculated equivalent vitrinite reflectance values range within 1.69%–2.20%. The data shows that the source rocks of all the Ediacaran and Lower-Middle Cambrian samples of the western China were deposited in an anoxic and stratified environment, with the initial organic matter showing a prevalence of type II kerogen (marine algal). The organic matter have experienced none or at least a very slight biodegradation rate, in spite that the maturity rate corresponds to post-maturity level.

Eukaryotic red and green algae populated the tropical ocean 1400 million years ago

Both molecular clocks and the fossil record indicate that eukaryotic algae evolved by the late Paleoproterozoic Era (2500 to 1600 million years ago, Ma). However, the biomarker record of steranes does not reveal their presence until the early Tonian Period (1000 to 720 Ma), suggesting that eukaryotic algae were insignificant ecosystem members for some one billion years after they evolved. Here, we conducted high-temperature pyrolysis and fixed-bed catalytic hydropyrolysis of kerogen from the ca. 1400 Ma Xiamaling Formation, liberating a host of lipid molecules, including C27 to C29 steranes. With sterane to hopane ratios ranging up to 0.17, our results indicate the presence of significant populations of both red and green algae at 1400 Ma, some 600 million years earlier than previously recognized. These algae actively contributed to primary production in what may have been a nitrogen-starved marine basin.

Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan

A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70–90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43–10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Δlog R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C19 tricyclic terpanes, C30 pentacyclic triterpanes, and C27 steranes. Maturity parameters (Tmax, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C23 TT, the lower amounts of C29/C30 17α(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., Tmax, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, ββ/ββ+αα), and the hopane Ts/(Ts + Tm) and C31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.

Characteristics and deposition models of the paleocene source rocks in the Lishui Sag, east China sea shelf basin: Evidences from organic and inorganic geochemistry

The Lishui Sag, situated at the East China Sea Shelf Basin, is regarded as one of the most prospecting oil exploration zones. Low exploration in this region requires detailed identification of source rocks to enhance further oil and gas exploration. Three potential source rocks, including the Paleocene Yueguifeng (E1y), Lingfeng (E1l) and Mingyuefeng (E1m) Formations, were investigated by integrating organic and inorganic geochemistry to estimate hydrocarbon generation potential, and to document original organic matter input and deposition environments. Two deposition models for source rocks were established considering tectonic subsidence and climate variation. The result shows that the E1y mudstones are dominated by high TOC content, oil/gas-prone kerogen at moderate maturity stage with relatively high hydrocarbon generation potential, whereas E1l and E1m mudstones are dominated by low TOC content, gas-prone kerogen at low to moderate maturity stage with low hydrocarbon generation potential, and coals with high hydrocarbon generation potential. The original organic matter input and deposition environment are obviously different among these three potential source rocks and are controlled by the coupling of tectonic subsidence and climate variation. Insufficient material supply lead mudstone deposition in a hemi-deep/deep lake during the E1y period, resulting in inefficient water mixing and stable water column stratification (high Gammacerane Indexs). The weak water inflow supplied minor oxygen and terrigenous organic matter to the lake due to arid-hot climate, as indicated by low Pr/Ph, C19 T/C23T, C20 T/C23T and C24Tet/C26T ratios, low Oleanane Indexs, and high C35 Homohopane Indexs and V/Ni ratios. Water algae, including pediastrums and chlorellas, which contributed to the development of high-quality source rocks, could be efficiently preserved in dysoxic condition. High subsidence rate together with sufficient sediment supply during the transgression in the E1l and E1m periods developed a coastal marine or paralic environment. The alternated climate brought unstable water inflow against stable water column stratification (low Gammacerane Indexs). Strong water inflow due to warm-humid climate provides abundant terrigenous organic matter and oxygen to the lake as indicated by high Pr/Ph, C19 T/C23T, C20 T/C23T and C24Tet/C26T ratios, high Oleanane Indexs, low C35 Homohopane Indexs and V/Ni ratios, and rich C29 steranes. Algal might be preferentially oxidized and degraded in aerobic conditions. Thus, mudstone is regarded as general-quality source rocks but coal is regarded as high-quality source rocks. Weak water inflow under arid-hot climate provided subtle aquatic and terrigenous organic matter to the lake, resulting in poor-quality source rocks.

Crude Oil Classification Based On Age And Provenance From The Southern Iraq: A Review

A collection of 165 crude oils, 12 oil seeps, and 24 extracts and recovered samples from 25 oil exploratory wells and 6 oil seeps in the Southern Mesopotamian Basin were studied. Biomarker configurations and other organic geochemistry parameters were used to discover the depositional environments and to classify the oil samples as provenance groups. Petroleum liquids were geochemically classified into four groups. The first group of oils, Middle Jurassic Zagros Fold Belt, is located in the Maysan, Basra, and Thi qar provinces of the basin that has pristane/phytane (Pr/Ph) proportions ≤0.97 and contains sufficient gammacerane. Methylphenanthrene index 1 (MPI 1) values show that the first group of oils is mature. Oils from Group 2, Upper Jurassic–Lower Cretaceous Sulaiy/Yamama, by disparity have Pr/Ph proportions between 0.72 and 1.12 and relatively moderate C28/C29 steranes, 0.52-0.88. Ts/Tm ratios indicate thermal maturity for Group 2 oils. Unlike oils from other groups, the oils from Group 3, Cretaceous to Tertiary oils, in Subba Field hold the highest canonical variable (CV) values that range between 0.43 and –2.30. The fourth group, Late Triassic-Middle Jurassic oil seeps, is the oldest among all groups. This group holds an average carbon isotope ratio –28.25‰ and –28.10‰ for saturates and aromatics respectively, which are the lowest values among all oils in the studied region. The Tithonian-Berriasian Sulaiy/Yamama oils further divided into three subgroups. The first subgroup, A, has carbon preference index (CPI) values of ≤1.08 (average 0.86) and C28/C29 sterane of 0.56-1.13 with an average of 0.65. Second subgroup, B, holds CPI ≤1.18 (average 0.99) and C28/C29 sterane 0.55-0.82 with an average of 0.63. The last subgroup, C, has CPI values ≤0.93 (average 0.85) and high C27 and C29 steranes (average 46.5% and 39.61%, respectively). In the same way, the Group 3 can be further subdivided into two subgroups based on values of carbon isotopes for saturates and aromatics. The oils from this group are heterogeneous and can be further divided into Tertiary Subgroup and Cretaceous Subgroup.

Organic geochemistry of source rocks in the Baiyun Sag of the Pearl River Mouth Basin, South China Sea

Source rock samples (i.e., drill cuttings) of the Wenchang, Enping, and Zhuhai formations from the Baiyun sag in the deep-water area of the Pearl River Mouth Basin (PRMB) in the South China Sea were collected and subjected to organic geochemical analysis. The three sets of potential source rocks were further divided into six types, based on biomarkers and carbon isotopic compositions: shallow lacustrine and semideep–deep lacustrine source rocks of Wenchang Formation, shallow lacustrine and marine transgression-related source rocks of Enping Formation, and littoral and neritic source rocks of Zhuhai Formation. The Wenchang Formation semideep–deep lacustrine source rocks developed in the Baiyun Sag are characterized by low ratio of C30 4-methylsteranes to C29 steranes (4-Me/C29 < 0.25) and relatively 13C-depleted isotopic compositions (δ13Ckerogen < −27.5‰), which are obviously different from those from shallow-water area in the PRMB. Rock–Eval analysis shows the Wenchang Formation develops good source rocks, which are better than those in the Enping Formation. The Zhuhai Formation does not contain effective source rocks because of its low maturity. According to the distribution of bicadinanes and oleanane, it is speculated that shallow lacustrine source rocks of Wenchang Formation in the northern Baiyun Sag have similar high bicadinanes to C30 hopane ((W + T)/C30H) and low oleanane to C30 hopane (OL/C30H) ratios to those of the Enping Formation, indicating their possible contribution to the discovered hydrocarbon accumulations. In summary, hydrocarbons generated by the Wenchang Formation source rocks should become the next key exploration target in the Baiyun Sag.

Origin, biodegradation, and water washing of bitumen from the Mishraq Sulfur Mine, northern Iraq

Bitumens from Middle Miocene Fat'ha Formation at Mishraq Sulfur Mine were investigated to determine their sources and the extent to which they may have been diagenetically altered. For these purposes, fourteen bitumen samples were subjected to detailed biomarker analysis using gas chromatography-mass spectrometry (GC-MS). Stable carbon and deuterium isotopes were also measured on chromatographic fractions. These bitumens are present in cavities and fractures of limestone from the native sulfur productive series. Polar fractions accounts for about half of the bitumen composition. These bitumens are showing a partial removal of n-alkanes; whereas their terpanes and steranes are intact. In addition, dibenzothiophene (DBT) and phenanthrene (Phen.) concentrations and DBT/Phen. ratio are variable among the samples. Most deuterium isotope values of asphaltene and resin fractions are similar to those of non-biodegraded bitumen seeps from the Qaiyarah area. These criteria suggest that bitumens of Mishraq mine are slightly affected by biodegradation and they are water washed to different extents but are not affected by abiotic oxidation. The biodegradation of these bitumens is mainly due to sulfate-reducing (anaerobic) bacteria.Terpane and sterane ratios suggest that bitumens were generated from early-mid mature carbonate source rocks deposited under reducing conditions. They show high values of C29/C30 and C35S/C34S hopane (>1.0), low values of diasteranes/regular steranes, Ts/Tm, moretane/hopane, and low values of Pr/Ph for most samples. Regular sterane distributions show dominance of C29 over C27 steranes. Middle and Upper Jurassic Sargelu and Chia Gara formations are proposed as source rocks for these bitumens; but Chia Gara is most likely.

Origin, geochemical characteristics and filling pathways in the Shadegan oil field, Dezful Embayment, SW Iran

The Shadegan oil field is one of the fields in the central part of the Dezful Embayment. Little or no geochemical studies have been performed previously in this field. This paper provides valuable information to answer most of the geochemistry ambiguities and issues in this field. Different techniques were used to investigate the genetic types of Asmari and Bangestan reservoirs. Structural characteristics of asphaltenes, biomarker fingerprints, and V/Ni ratio indicates that all oils in the Shadegan field have similar source rock(s) and belong to one oil family. The homologous series of normal alkanes distribution and the absence of 17α(H) 25-hopane reveals that biodegradation has not affected oil samples and planktons/algal or higher plants are dominating organic matters, proved by hopanes/steranes ratio. The Pr/Ph < 1, 0.49 < V/(V + Ni) < 0.81, and homohopanes distribution implied an anoxic condition during source rock deposition. The DBT/Ph, C24/C23 tricyclic terpanes, C22/C21 tricyclic terpanes, C29/C30 hopane, diasterane/sterane ratios suggest that the contribution of clay to source rock was insignificant and source rock has composed of a mix shale and carbonate. Steranes show C29 > C27 > C28 pattern, and the ternary diagram of steranes confirmed that the source rock deposited in the open marine environment and oil samples originated from marine organic matters. All samples have been sourced from a source rock(s) older than the Upper Cretaceous, as shown by the oleanane ratio. The Kazhdumi Formation is the primary source rock in this field, and some contributions from other source rocks might have occurred. In general, samples indicate maturity before the peak of the oil window in which the Bangestan samples have lower maturity regarding the Asmari samples based on aromatic and saturate maturity parameters. The tracing of oil filling pathways by isopleth maps of 4-/1-MDBT and C29 sterane 20S/(20S + 20R) ratios revealed that each reservoir had been charged from several directions. Although the Upper Asmari and Bangestan reservoirs have been charged laterally, the Lower Asmari has been charged vertically and laterally.

Geochemical characteristics and significance of the bitumen in Sinian reservoirs in Sichuan basin and its periphery

The bitumen of Doushantuo Formation distributed along fractures has been firstly discovered in the dolomite reservoirs of Dou-3 Member in Zigui region, Yichang, Hubei. Research has been conducted using multiple methods on the characteristics of the newly discovered bitumen of Doushantuo Formation, bitumen of Dengying Formation-Longwangmiao Formation in Anyue gas field in Sichuan Basin, and bitumen of Sinian and source rocks of Sinian-Cambrian in Northeast Sichuan. The results show:①The reflectivity of the bitumen of Dou-3 Member is about 2.8%; ② The carbon number of n-alkanes in the bitumen of Dou-3 Member is C13-C33, where nC17 is the main peak; the relative proportion of the regular steranes is C27≈C29>C28, and C27, C28 and C29ααα20R steranes are distributed in “L” shape; abundant tricyclic terpanes and pentacyclic triterpanes have been detected, and the abundance of gammacerane is high; Aromatics are mainly phenanthrene series compounds. ③ The heteroatomic compounds in the bitumen of Dou-3 Member are mainly O2 carboxylic acids, and the oxygen compounds in the bitumen of Dengying Formation in Anyue gas field are close to those of the source rocks of Doushantuo Formation. The research results are of vital guiding significance to the study of potential source rocks of Doushantuo Formation in Sichuan Basin and the exploration of oil and gas from the source rocks of Doushantuo Formation.

Oil origins, mixing and biodegradation in southwestern Junggar Basin, NW China

The southwestern Junggar Basin is an attractive region for oil exploration. A major discovery of high oil production rate from a recently drilled borehole stimulated a new round of extensive petroleum exploration in this region. The potential source beds are within the Permian, Triassic, Jurassic, Cretaceous and Paleogene strata, but no effective oil-prone source rock samples have been drilled so far due to deep burial, leading to that oil source correlation remains controversial in the region. A total of 38 crude oils and the free, adsorbed and inclusion oils obtained from 18 oil-containing reservoir rocks from the southwestern and southern Junggar Basin were analyzed by GC, GC–MS and GC–IRMS for the purpose to classify oil groups, determine oil origins, and identify effective source beds in sags. Crude oils in the southwestern Junggar Basin can be classified into two end groups and an intermediate group, namely PO, JO and PJO oils, which were originated from the Permian lacustrine source beds, Jurassic terrigenous source beds and both, respectively. Ratios of C19/C20 tricyclic terpanes and C24 tetracyclic/(C24 tetracyclic + C26 tricyclic) terpanes are the most sensitive parameters to distinguish these three groups of oils. These two ratios increase from PO, PJO to JO oils. JO oils can be further classified into two subgroups, i.e. J1O and J2O. J2O oils have substantially higher amounts of C27 and C28 steranes relative to C29 steranes, higher amount of gammacerane, lower amount of C29 diasteranes, and lower isomerization ratios of steranes, compared with J1O oils. J1O oils were exclusively originated from the Jurassic source beds while J2O oil were mainly originated from the Jurassic source beds mixed with minor oils generated from the Paleogene and Cretaceous lacustrine source beds. In the Chepaizi uplift, the major PO oils and extracted oils from 14 reservoir rocks were mainly originated from source beds within the Lower Wuerhe Formation of Middle Permian (P2w). However, the remaining minor oil samples and extracted oils from the other four reservoir rocks were clearly originated from source beds in the Fengcheng Formation of Lower Permian (P1f) on the basis of molecular parameters and δ13C values of individual n-alkanes, indicating the presence of effective oil-prone source beds within the Fengcheng Formation in the Shawan sag. In shallow reservoirs within the Neogene Shawan Formation (N1s), PO, PJO and J1O oils are severely biodegraded while J2O oils have nearly no biodegradation effect because the former entered the reservoirs much earlier than the latter.