Peak Oil Generation Research Articles

Geochemical characteristics and origin of crude oil from Carboniferous volcanic rocks in the Hongche Fault Zone of the Junggar Basin of China

In recent years, significant advances have been made in the exploration of Carboniferous volcanic reservoirs in the Hongche Fault Zone of the Junggar Basin of China, showing good prospects for further exploration. However, the large variation in the physical properties of crude oil and the complex distribution rule inhibit the one-step exploration. In this study, the PM scale of the biodegradation of crude oil and source of crude oil were studied using experimental methods that target the properties, bulk properties and biomarker compounds of crude oil. The exploration potential of crude oil in this area was analysed, and an accumulation model of crude oil was established. Based on the differences in biomarker compounds and the degree of biodegradation, crude oils were divided into four groups and seven subgroups. Additionally, the analysis of the biomarker compounds of crude oil combined with the hydrocarbon-generation history of source rocks showed that there were at least two periods of oil charging in this area. The first period was the late Triassic, with crude oil derived from the P1f source rock. Owing to the strong tectonic activity during the late Indosinian movement, the oil reservoirs were distributed in the footwall of the fault zone, and the oil in the reservoir exhibited different degrees of biodegradation, forming crude oils of subgroup I1, II and III1. The second period was Cretaceous, during which the P1f source rock was in the natural gas generation stage, and the P2w source rock was at a mature stage. A small part of the crude oil formed by the P2w source rock migrated to the Carboniferous reservoirs and mixed with the crude oil formed by the earlier P1f source rock, resulting in crude oils of subgroups I2, III2, and IV2. The crude oil in the studied area originated from the source rocks in the sag during the peak of oil generation. As tectonic activity approached stability in the latter period, it is speculated that there may be well-preserved primary oil and gas reservoirs in the footwall and slope areas of the fault, making these potential exploration sites.

Nanomechanical characterization of organic-matter maturity by atomic force microscopy (AFM)

Characterizing the thermal maturation of organic matter is essential to oil and gas resource evaluation and generation mechanisms, but is extremely challenging in nanoscale vitrinite-dominated formations (few suitable vitrinites in micron scales for traditionally microscope petrographic analyses), forming a critical issue in oil and gas geochemistry requiring new solutions. Here we considered Permian source rocks in the Junggar Basin, China, as a case study for the application of a new method for characterizing maturity based on nanomechanical properties. Atomic force microscopy (AFM) was used to characterize the nanomechanical properties of vitrinite at different maturity levels, and the results were combined with a micro-Fourier-transform infrared (FTIR) study to examine the chemical structural response to changes in mechanical properties. The Young's modulus of vitrinite increases in an S-shaped trend with maturity, reflecting differences in chemical structure at different evolutionary stages. In the early stage of maturity (< 0.7% Ro), vitrinite is relatively soft with a heterogeneous mechanical structure. On reaching the oil-generation threshold (∼0.7% Ro), the removal of aliphatic structures leads to a significant increase in Young's modulus. At the oil-generation peak (∼1.0% Ro), the Young's modulus increase slightly. When the vitrinite enters the gas window (> 1.3% Ro), the higher aromatization level results in a high Young's modulus, with mechanical structure becoming more homogeneous. The results show that maturity can be effectively characterized on the basis of the nanomechanical properties of vitrinite. This method has unique advantages in determining the maturity of organic matter with vitrinites being dominated by nanoscale particles, which cannot be easily measured by conventional microscopes. Thus, the AFM method is a useful supplement to the traditional vitrinite reflectance measurement.

Impact of thermal maturity on the diagenesis and porosity of lacustrine oil-prone shales: Insights from natural shale samples with thermal maturation in the oil generation window

Shale diagenesis controls the generation, migration and accumulation of hydrocarbons through time and has become a frontier area of study in the fields of sedimentology and petroleum geology. There have been only a few studies on the generation of organic pores in lacustrine shale oil reservoirs during the oil generation thermal evolution stage. In this study, lacustrine organic-rich shale samples at various stages of maturity, from the first member of the Songliao Basin Qingshankou Formation were investigated, and a thermal transformation law of macerals was established, based on organic petrology. The diagenetic alteration styles and sequences were investigated using a high-resolution field emission scanning electron microscope, and cathode luminescence. Furthermore, automated pore extraction technology enabled the examination of the characteristics and genetic process of organic and inorganic pores under the influence of thermal maturation. The results indicate that a small quantity of pre-oil bitumen is generated during the early oil mature stage (Ro: 0.7% - 0.9%), and that the generation of a large quantity of post-oil bitumen that occurs following the peak oil generation stage (i.e., late oil mature stage, Ro: 1.1% - 1.4%), is controlled by the unimodal distribution of the activation energy of Type I kerogen. Compaction intensity certainly influences pore volume reduction. Siliceous cementation primarily occurs during peak oil generation maturity and the subsequent thermal evolution stage. The pores formed in the oil generation window primarily arise from mineral dissolution and organic matter polycondensation. Following peak oil generation, the pores undergo iron dolomitization, smectite illitization, and bitumen cracking. The degree of development of inorganic pores, the most common pore type in shale oil reservoirs, appears to have a significant impact on the total porosity of a reservoir shale. During thermal evolution, the inorganic pore volumes show a decreasing trend. There is a secondary pore development stage, reached when Ro exceeds 1.2%, closely related to the transformation of clay minerals. According to the hydrocarbon generation kinetics and compaction model, organic pore volumes increase gradually at 0.7%Ro, reach their peak at 1.1%Ro, and then steadily decrease due to compaction. The organic pores are relatively well developed when Ro is >0.85% (at the start of the oil window). The shale oil reservoir's most favorable thermal evolution stage is late oil maturity stage that follows the oil generation peak.

Petroleum generation modelling of the Middle‐Late Cretaceous sediments in the Abu Gharadig Field, Northwestern Desert, Egypt

The present work introduces an integral study concerning the Middle‐Late Cretaceous source rocks in Abu Gharadig (AG) Field utilizing source rock evaluation techniques and hydrocarbon generation modelling. The used methods include TOC%, Rock‐Eval pyrolysis, vitrinite reflectance (Ro%), and 1D basin modelling data. Our results show that most of the studied marine Middle‐Late Cretaceous intervals in AG Field are considerable as source rocks, excluding the Abu Roash A‐D members. The Kharita, Bahariya, and Abu Roash E &amp; G intervals have mainly gas‐prone kerogen. The Abu Roash F and Khoman B members contain mixed kerogen type II/III with oil/gas‐prone generative potential. Khoman A member has marine type II kerogen with mainly oil‐ and minor gas‐prone generative potential. Among the Middle‐Late Cretaceous rock units, the Khoman Formation is either immature or early mature, whereas others are mature enough to generate hydrocarbons. The burial history models typify a high subsidence rate during the deposition of Kharita, Bahariya, and Abu Roash formations in response to the Tethyan rifting phase. The timing of the peak of oil generation window for the Abu Roash G interval is ranged as Late Oligocene‐Early Pliocene time. Moreover, the timing of the peak of oil generation for the Abu Roash F interval is ranged as Early Miocene‐Latest Miocene. Based on transformation ratios (TR), the Abu Roash F member demonstrates a limited hydrocarbon expulsion (25% &gt; TR &lt;50), whereas both Abu Roash G and Khoman B members can generate in‐situ hydrocarbon (TR ≤10%). Compiling data along the AG basin from previous works infers that there are spatial and temporal discrepancies in organics composition and thermal maturity of the Middle‐Late Cretaceous intervals. Changes in paleoclimate, eustatic, and basin tectonics can be considered as the primary drivers that triggered such spatiotemporal variation. Integrated approaches are needed to constrain the multi‐geospheric interactions of major Cretaceous anoxic events in the Northwestern Desert of Egypt, and to explore the driving forces on these organics‐accumulating events.

Mechanism of differential enrichment of shale oils in the upper and lower members of the Lucaogou Formation in the Jimusaer Sag, Junggar Basin

Shale oil exploration and development have been conducted in the Permian Lucaogou Formation in the Jimusaer Sag, Junggar Basin. The upper (P2l2) and lower (P2l1) members of the Lucaogou Formation developed with sand layers, which are the shale oil development sections in the Lucaogou Formation. In order to clarify the enrichment law of shale oil for these members, the geological conditions of the P2l2 and P2l1 members were analyzed. The focus of this study were oil-bearing sandstone and mudstone samples from the Lucaogou Formation. These samples were studied by casting thin section observation, total organic carbon, pyrolysis, and gas chromatography–mass spectrometry. The results showed that the upper and lower members of the Lucaogou Formation are mainly characterized as interbedded source rock and reservoir. An oil-source correlation showed that the crude oil in the upper member mainly originated from its adjacent source rock from a deeper position through secondary migration. However, no evidence of secondary migration was observed in the crude oil in the lower member which mainly originated from the adjacent source rock. For the sandbodies in the upper member, when burial is shallower than peak oil generation, the physical properties of the middle part of the sandbody are better than the top and bottom. When burial is deeper than peak oil generation, relatively good physical properties developed in the sandstone in the vicinity the source rock. The lower member has less reservoir thickness, poorer lateral continuity and horizontal permeability than the upper member. The high-quality reservoirs are represented in a single sandbody in the lower member that is mainly developed in the middle part. After the crude oil was discharged from the source rock enters the sandbody, and long-distance lateral migration was restricted. Thus, crude oil in the lower member is enriched and accumulated in situ.

Carbon-hydrogen isotopic systematics of gases generated in semi-closed hydrous pyrolysis of type I source rock with the presence of formation water: Implications for gas isotope partitioning under supercritical conditions

Hydrocarbon gas is a significant type of clean energy, and understanding its carbon-hydrogen (C–H) isotopic behaviour during hydrocarbon generation is essential for determining the gas genesis. Hydrous pyrolysis is an artificial method to simulate natural gas generation process with the presence of water. Formation water is a type of ubiquitous saline water in oilfields, whereas not commonly utilized in hydrous pyrolysis. To determine the influence of formation water on C–H isotopic systematics of hydrocarbon gas (methane, ethane and propane), two series of semi-closed hydrous pyrolysis experiments were conducted in 275–550 °C for the type I Green River Shale source rock using distilled water and formation water. Hydrocarbon gases generated in two series of experiments have similar δ13C ratios yet slightly different δD ratios at individual temperatures, which is likely attributed to the water-organic interaction as formation water has a different δD ratio compared to distilled water. The δ13C and δD ratios of gas increase with the rising of thermal maturity level, and exhibit quadratic correlations with vitrinite reflectance (VR) values in both series of experiments. The presence of supercritical water in hydrous pyrolysis does not significantly affect the gas C–H isotopic partitioning behaviour because gases collected below and above the critical temperature (374.2 °C) display consistent δ13C (δD)-VR patterns. Partial C–H isotopic reversals (δ13C2>δ13C3, δD2>δD3 or δD1>δD2) are observed during the pre-oil to oil generation peak and gas generation stages, which are likely mainly affected by gas mixing as evidenced by rigorous correlations between δ13Cn (δDn) ratios and reciprocals of the gas proportion (1/Cn).

Excellent source rocks found along the margin of a large lacustrine basin: Case study from the Ordos Basin, China

Whether the Chang 6 oil pools of the Triassic Yanchang Formation in the Ansai-Yanchang (AY) oil province on the Yishan slope of the Ordos Basin formed from near source rock or far source rock has long been debated. An understanding of the source rock's position will impact the formation mode and distribution of accumulations in this area. Based on the geochemical data of the Chang 7 source rock in six wells and 18 crude oil samples, the geochemical characteristics of Chang 7 source rock and its relationship with Chang 6 crude oil were studied. There are two types of source rocks, namely, black shales and dark mudstones, present in the AY area. The gross thickness of the Chang 7 black shale is 3.0–19.7 m, with a distribution area of 5500 km2. It has an average total organic carbon (TOC) content of 3.34%, with a chloroform bitumen “A" content of 0.512%, indicating good to excellent source rock potential. The kerogen assessment with core samples shows mixed type I-II1, and has reached peak oil generation, maximum pyrolysis temperatures (Tmax) ranging from 445 to 458 °C. In contrast, the average TOC content of the dark mudstone in Chang 7 is 0.91%, chloroform bitumen “A” is 0.079%, the main type of kerogen is type II2-II1, and Tmax varying from 446 to 461 °C, indicating only fair source rock potential overall. The Chang 7 source rocks in the AY area have a gammacerane index of 0.07–0.38, with an average value of 0.21, which reflects a low-salinity fresh to brackish water environment. The relative abundances of C27, C28, and C29 steranes are 29.7%, 23.1% and 47.2%, respectively, indicating that terrestrial higher plants and aquatic organisms provide similar contribution in the Chang 7 source rocks. Oils produced from the AY area of the Chang 6 member have similar geochemical signatures, but are significantly different from the Chang 6 crude oils in the Daozhen (DZ) area of Ganquan County and the Huaishuzhuang (HSZ) area of Fuxian County, which are located in the center of the lacustrine basin. They differ in terms of the maturity of the oil samples and the microscale composition of the parent material type. The closer the wells are to the center of the lacustrine basin, the higher the maturity of the source rock and the greater the contribution of aquatic organisms. The variation of carbon isotopic composition of Chang 6 crude oil in AY area is consistent with that of Chang 7 shale locally, but opposite to that of Chang 6 crude oil in DZ area. The ratios of nC21-/nC22+, tricyclic terpane/hopane and C29 sterane ββ/(ββ+αα) biomarker parameters of Chang 6 crude oils in AY area are similar to those of Chang 7 shale in local area, but deviate from those of DZ and HSZ area. These data results reveal that the Chang 6 crude oils in the AY oil province are dominated by the local Chang 7 excellent source rocks rather than by the long-distance migration of oils from the basin center.

Key oil accumulation periods of ultra-deep fault-controlled oil reservoir in northern Tarim Basin, NW China

A giant fault-controlled oilfield has been found in the ultra-deep (greater than 6000 m) Ordovician carbonate strata in the northern Tarim Basin. It is of great significance for hydrocarbon accumulation study and oil exploitation to determine the key oil accumulation periods. Based on detailed petrographic analysis, fluid inclusion association (FIA) in calcite samples filling in fractures from 12 wells were analyzed, and key accumulation periods of the strike-slip fault-controlled oilfield was studied by combining oil generation periods of the source rocks, formation periods of the fault and traps, and the fluid inclusion data. (1) There are multiple types of FIA, among them, two types of oil inclusions, the type with yellow fluorescence from the depression area and the type with yellow-green fluorescence from the uplift area with different maturities indicate two oil charging stages. (2) The homogenization temperature of the brine inclusions in FIA is mostly affected by temperature rises, and the minimum temperature of brine inclusions symbiotic with oil inclusions is closer to the reservoir temperature during its forming period. (3) FIA with yellow fluorescence all have homogenization temperatures below 50 °C, while the FIA with yellow-green fluorescence have homogenization temperatures of 70–90 °C tested, suggesting two oil accumulation stages in Middle–Late Caledonian and Late Hercynian. (4) The Middle–Late Ordovician is the key formation period of the strike-slip fault, fracture-cave reservoir and trap there. (5) The oil generation peak of the main source rock of the Lower Cambrian is in the Late Ordovician, and the oil accumulation stage is mainly the Late Ordovician in the depression area, but is mainly the Early Permian in the uplift area. The key oil accumulation period of the strike-slip fault-controlled reservoirs is the Late Caledonian, the depression area has preserved the primary oil reservoirs formed in the Caledonian, while the uplift area has secondary oil reservoirs adjusted from the depression area during the Late Hercynian. Oil reservoir preservation conditions are the key factor for oil enrichment in the strike-slip fault zone of northern Tarim, and the Aman transition zone in the depression is richer in oil and gas and has greater potential for exploration and development.

Mechanism for the formation of natural fractures and their effects on shale oil accumulation in Junggar Basin, NW China

Despite the importance of natural fractures in shales, few techniques are currently available to examine their formation mechanism and effects on shale oil accumulation directly. The Middle Permian Lucaogou Formation in the Jimsar Sag of the Junggar Basin is a typical fractured shale. The Jimsar Sag has experienced multiple phases of tectonic movement since the Paleozoic Era, forming numerous natural fractures. However, controversy still surrounds the timing of formation, genetic mechanisms, and effects on shale oil accumulation of these fractures. Based on C-O-Nd isotopes, rare earth elements, fluid inclusions, SmNd isochron dating of fracture cements, rock acoustic emission, and triaxial rheological experiment, this study precisely define the fracture formation time, trace the provenances of fluids filling the fractures, elucidate the genetic mechanism of fractures and their effects on shale oil accumulation. The results suggest that these fractures were mainly formed in the Late Permian, Late Jurassic, and Early Cretaceous. Palaeotectonic stress field simulations further show that the tectonic movements in the Late Permian formed nearly N-S-trending fractures due to severe north-south extrusion. High-temperature fluids originating from the post-collision mantle intruded the Lucaogou Formation between ~258.1 Ma and ~ 257.6 Ma. Subsequently, tectonic movements in the Tianshan Mountains during the Late Jurassic resulted in extrusion from southwest to northeast, forming NEE-trending fractures. During this tectonic event, basin fluids intruded the Lucaogou Formation between ~150.2 Ma and ~ 146.5 Ma. The persistent fold rollback that occurred in the Bogda piedmont foreland sag in the Early Cretaceous subjected the Jimsar Sag to severe extrusion, forming NNW-trending fractures. This tectonic event influenced the intrusion of basin fluids into the Lucaogou Formation between ~123.0 Ma and ~ 120.3 Ma. The Late Jurassic and Early Cretaceous fractures coincided with the peak of oil generation and expulsion in the Lucaogou shale and created conduits and reservoir volumes for the migration and accumulation of shale oil. Our study introduces a new approach that integrates geophysical and geochemical data to investigate the formation processes of fracture and their impact on shale oil accumulation.

Thermal stability and parameter validity of hopane series in mature shales – A case study from Dongying Depression, eastern China

Molecular compositions extracted from source rocks offer direct indicator of the organic matter input, depositional redox conditions and thermal maturity levels that source rock has experienced, however, the application of such technique commonly encounters difficulty in highly mature system. A suite of twenty-eight organic-rich lacustrine shale samples from the Eocene Shahejie Formation in the Dongying Depression, East China were geochemically investigated, aiming to obtain a comprehensive thermal stability sequence of hopanes and the validity of various molecular parameters. By means of systematic comparisons on compound ratios and concentrations, the thermal stability of hopanes is presented as follows: [C35 hopane (H) < (C33H, C32H) < C34H < C30H < C31H < C29H < 17α(H)-22,29,30-trisnorhopane (Tm) < 18α (H)-30-norneohopane (C29Ts) < C30 diahopane (D) < 18α(H)-22,29,30-trisnorneohopane (Ts), from the least stable to the most stable]. Limited validity of the paleoenvironment and organic matter input parameters such as C35H/C34H and C31 22R/C30H ratios in mature source rocks is caused by the preferential decomposition of C35H and C30H compounds during thermal maturation. Therefore, application of molecular parameters derived from hopanes need to be exercised with extra caution. Their validity varies with maturity levels and most hopane related parameters will lose their effectiveness at peak oil generation stage. Meanwhile, a novel maturity parameter (Ts/C29Ts ratio) derived from thermal stability difference of hopanes was proposed herein, supported by strong correlations with vitrinite reflectance and other two reliable maturity parameters. Upon further calibration, this novel maturity parameter can be deemed as a reliably alternative indicator and is expected to have wide application in highly mature source-rock/oil maturity assessment, especially for the shale oil system. The findings of this study may help for better understanding of limited validities of molecular indicators during thermal evolution.

Semi-closed artificial thermal maturation of type I source rock with the presence of natural formation water: hydrocarbon generation and individual n-alkane stable carbon isotope partitioning pattern

Hydrous pyrolysis is a significant laboratory method to investigate oil generation with the presence of water. Generally, distilled water is utilized in hydrous pyrolysis but not natural formation water, which is ubiquitous in oilfields and has elevated salinities. To understand the influence of formation water on hydrocarbon generation and stable carbon isotopic ratios of expelled oils, two series of semi-closed hydrous pyrolysis experiments were conducted in a wide temperature range (250–550 °C) for the type I Green River Shale source rocks using distilled water and formation water with a salinity of 76 g/L. Oil generation peak occurred at a lower temperature (325 °C) in experiments using formation water compared to experiments using distilled water (375 °C), suggesting that the presence of formation water has facilitated the oil generation. The presence of formation water also promoted the hydrocarbon expulsion at lower temperatures in hydrous pyrolysis (325–350 °C). Stable carbon isotopic fractionation between unpyrolyzed kerogen and n-alkanes (n-C17 to n-C28) generated during the primary stage of oil generation (325–375 °C) is minor (<2.6‰) in the presence of formation water, but smaller relative to those in experiments using distilled water at individual temperature points. Positive correlations between pyrolysis temperatures and δ13C ratios of n-C17, n-C18 and n-C19 during oil generation were observed in the experiments using formation water, which is consistent with the knowledge that 12C–12C bonds are more readily to be cleaved than 13C–12C bonds. Outcomes of this study not only support that stable carbon isotopic analysis of n-alkanes is a powerful tool for fingerprinting oil source in sedimentary basins, but also highlight the significance of using formation water as a medium in hydrous pyrolysis to improve the understanding of chemical/isotopic variations during hydrocarbon generation.

Organic geochemical and petrographical characteristics of the major lower cretaceous petroleum source rock (Makhul Formation) in Kuwait - Arabian Gulf

The Lower Cretaceous Makhul Formation is one of the major petroleum source rocks in Kuwait. This study aims to evaluate the Makhul source rock for its organic matter richness and its relation to the rock composition and depositional environment. A total of 117 core samples were collected from five wells in Raudhatain, Ritqa, Mutriba, Burgan, and Minagish oil fields north and south Kuwait. The rock petrographical studies were carried out using a transmitted and polarized microscope, as well as SEM and XRD analyses on selected samples. Total organic matter TOC and elemental analyses were done for kerogen type optically. The GC and GC-MS were done as well as the carbon isotope ratio. The results of this study show that at its earliest time the Makhul Formation was deposited in an anoxic shallow marine shelf environment. During deposition of the middle part, the water oxicity level was fluctuating from oxic to anoxic condition due to changes in sea level. At the end of Makhul and the start of the upper Minagish Formation, the sea level raised forming an oxic open marine ramp depositional condition. Organic geochemical results show that the average TOC of the Makhul Formation is 2.39% wt. High TOC values of 6.7% wt. were usually associated with the laminated mudstone intervals of the formation. The kerogen is of type II and is dominated by marine amorphous sapropelic organic matter with a mixture of zoo- and phytoplankton and rare terrestrial particles. Solvent extract results indicate non-waxy oils of Mesozoic origin that are associated with marine carbonate rocks. The formation is mature and at its peak oil generation in its deepest part in north Kuwait.

Organic geochemistry, oil-source rock, and oil-oil correlation study in a major oilfield in the Middle East

In this study several major source rocks: Kazhdumi, Pabdeh, and Gurpi formations, along with crude oils from the Asmari and Bangestan reservoirs in the Gachsaran oilfield, southwestern Iran, were investigated from the organic geochemistry point of view. Results indicate that the Kazhdumi and Pabdeh formations have excellent generation potential and are mature and immature source rocks, respectively. In contrast, the Gurpi Formation has lower petroleum generation potential. The organic matter in the Kazhdumi and Pabdeh formations in the neighboring synclines within the Gachsaran oilfield is in the late and peak oil generation stages, respectively. SARA composition by Liquid Chromatography performed on four crude oils produced from these source rocks suggest a paraffinic-naphthenic composition. The source rocks had carbonate and shale lithology. Distinct biomarkers point to an open marine environment characterized by marine kerogen Type II and mixed Types II/III deposited under anoxic-suboxic depositional conditions, although. The presence of relatively high amounts of oleanane in the oils points to contribution from a terrigenous source. Based on biomarkers, the four oils exhibit similar thermal maturity, which is equivalent to the primary stage of oil generation. The star diagrams of various normal alkanes and biomarker ratios show that the four crude oil have high similarities, which suggests a single source origin. Nonetheless, utilizing different ML methods of K-means Clustering, Fuzzy C-means clustering (FCM), Comptlayar Neural Network, Construction of agglomerative clusters, and the obtained dendrogram all suggest that there are two oil families in the Gachsaran oil field. Furthermore, geochemical parameters including specific biomarkers denote the contribution of the Kazhdumi and Pabdeh formations in the Gachsaran oil field whereby charges of mixed origins at different reservoir horizons of Asmari and Bangestan can be identified. Ultimately, two scenarios for the presence of oleanane in Bangestan reservoir are envisaged: 1) connectivity of the Asmari and Bangestan reservoirs as a result of natural fracturing, and 2) emplacement of the Pabdeh Formation near the vicinity of the Bangestan reservoir as a result of thrust faulting. Overall, this study demonstrated that integration of data analytics (ML) methods with conventional geochemical techniques can precisely delineate the correlation between the generated oil and the source rocks. • Geochemical analysis performed on two rarely studied major source rocks in Middle East: kazhdumi and Pabdeh Formations. • Several machine learning (ML) algorithms were implemented to identify existing oil families from these two source rocks. • These two oil families were also confirmed by detection of the Oleanane biomarker in separated oil groups.

Geochemical Characteristics of Expelled and Residual Oil from Artificial Thermal Maturation of an Early Permian Tasmanite Shale, Australia

Lipid biomarkers play an important role in defining oil-source rock correlations. A fundamental assumption is that composition (or ratios) of biomarkers in oil is not significantly different from that in bitumen in the source rock. In order to compare the geochemical characteristics of expelled oil and residual oil, a Permian Tasmanite oil shale was used for an artificial maturation experiment to simulate the oil generation period. The results show that the Tasmanite oil shale generated high amounts of hydrocarbons (731 mg HC/g TOC) at low maturation temperatures (340 °C). The hydrocarbon (HC) group compositions are different between the expelled oil (with more aromatic HC and saturated HC) and the residual oil (with more resin fraction and asphaltene). The Pr/Ph ratio (up to 4.01) of the expelled hydrocarbons was much higher than that in residual oil (&lt;1.0). Maturity-related biomarkers Ts/(Ts + Tm), and αααC29-20S/(20S + 20R) and C29-αββ/(ααα + αββ), also showed complicated variations with pyrolysis temperature, especially at post peak oil generation. C27-, C28-, and C29- sterane distributions showed variations with pyrolysis temperature. Therefore, without considering the influence of maturity on the abundance of compounds, either source, maturity and/or organic matter type from the chemical characteristics may not be correct.

Revisiting Controls on Shale Oil Accumulation in Saline Lacustrine Basins: The Permian Lucaogou Formation Mixed Rocks, Junggar Basin

Fine-grained mixed rocks in saline lacustrine basins are important targets for shale oil exploration. However, the controls on shale oil accumulation are complex due to the multi-source mixed deposition. This is a challenging issue in the study of shale oil. Here, we present a case study in the Middle Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwestern China. Results show that the Lucaogou Formation consists mainly of carbonate rocks, dolomitic or calcareous mudstones, tuffaceous or silty mudstones, and siltstones. The dolomitic/calcareous mudstones (TOCaverage=6.44 wt.%) and tuffaceous/silty mudstones (TOCaverage=4.83 wt.%) have the best hydrocarbon generation potential and contain type I–II1 kerogens that are in the peak oil generation stage. However, the shale oil potential is highest for the carbonate rocks and siltstones with average oil saturation index (OSI) values of 315.03 mg HC/g TOC and 343.27 mg HC/g TOC, respectively. This indicates that hydrocarbon generation potential is not the main factor controlling shale oil potential. Micro-nanoscale pores are the main control. Abundant dissolution pores provide excellent reservoir space for near-source migration and accumulation of shale oil. Different mixing processes between lithofacies control the accumulation of shale oil, and shale oil productivity is the best when multi-facies deposition in transitional zones formed the mixed rocks (facies mixing). In addition, local accumulations of calcareous organisms and adjacent carbonate components on terrigenous sediments (in situ mixing) are also conducive to shale oil enrichment. This is an unusual and special feature of saline lacustrine shale oils, which is different from freshwater lacustrine and marine shale oils. Comprehensive assessment of source rock and reservoir is needed to robustly establish a widely applicable method to determine the shale oil potential in such basins.

Molecular structure evolution of Type I kerogen during pyrolysis: Case study from the Songliao Basin, NE China

To characterize molecular structure evolution of Type I kerogen, we performed gold tube pyrolysis experiments on a Cretaceous Qingshankou lacustrine mudstone in the Songliao Basin during artificial maturation. The hydrocarbons generated at 320–600 °C at two heating rates, 2 and 20 °C/h were quantified, and the maximum yields of C14+, C6-14 and C2-5 gaseous products corresponded to vitrinite reflectance (Ro) nodes of 1.18%, 1.76% and 2.5%, respectively. Chemical compositions of solid residues (pyrolysis products remaining after extraction by dichloromethane and methanol) with Easy%Ro values ranging from 0.49 to 2.5% were studied by elemental analysis and nuclear magnetic resonance. With increasing temperature, the solid residues presented sharp decreases in aliphatic fractions and significant increases in aromatic fractions, while a condensation reaction occurring in the residue was related to secondary coking and cracking reactions occurring after the peak oil window. Four structural models of the residues were investigated, demonstrating that three positive nonlinear stages occurred between fused aromatic carbon (XE BP) structures and hydrocarbon generation. At Easy%Ro < 0.89, the XE BP numbers were relatively stable, and the generated hydrocarbons mainly attributed to cleavage of heteroatomic functional groups (NSOs) of kerogen. During the peak hydrocarbon-generating stage (Easy%Ro values of 0.89–1.76), the XE BP numbers exhibited an obvious increase due to breaking of carbon chains and cyclization reactions, which was accompanied by formation of large quantities of C14+ oils and C6-14 hydrocarbons derived from direct cracking of kerogen. The XE BP numbers were growth slowing and highly cross-linked features at Easy%Ro values of 1.76–2.5% due to polycondensation, and a large amount of C2-5 gas generation was mainly attributed to oil cracking. A good coupling relationship between H/C atomic ratio and polycondensation of aromatic structures in evolution further strengthens research of molecular structure evolution in Type I kerogen. Moreover, comparison of the number of aromatic structures caused by alkyl bond breakage and condensation showed that the number of the former was higher than that of the latter before the peak of oil generation, whereas the number of the latter was obviously dominant after the peak of oil generation.

The offshore Mancos play in the San Juan Basin as a component of the Mancos total petroleum system

Historically, the offshore Mancos play of the San Juan Basin has produced oil from noncommercial to marginally commercial reservoirs consisting of dark-gray marine shale with thin beds and laminae of fine-grained sandstone of limited permeability. During the last decade, horizontal drilling with horizontal wells has resulted in substantially increased production. However, placement of the offshore Mancos play within the Mancos total petroleum system has been poorly understood. Here, the offshore Mancos play is interpreted as a carrier bed play within the Mancos total petroleum system. Unconventional reservoirs of the offshore Mancos play are stratigraphically equivalent to updip conventional reservoirs deposited nearer to the shoreline and to downdip source rocks matured to peak oil generation. Offshore Mancos facies include a proximal facies to the southwest, a medial facies, and a distal facies to the northeast. Oil production has been obtained from the proximal and medial facies. Mancos shales contain oil-generative kerogens that are within the upper oil window near conventional reservoirs in the south and have matured to peak oil generation downdip of and to the northeast of the offshore Mancos reservoirs. Uniform API gravities of light sweet produced oils that transcend thermal maturity variations of Mancos shales indicate that oils generated in downdip mature source rocks migrated updip through the carrier bed sandstones of the offshore play and into the conventional reservoirs. Residual oil saturations are consistent with the concept of migrating oils moving updip through only a small number of interconnected pathways within a carrier bed.

Exhumation filling and paleo-pasteurization of the shallow petroleum system in the North Slope of the Biyang Sag, Nanxiang Basin, China

Deposits of biodegraded heavy oils are commonly encountered within the Eocene reservoir units in the North Slope of the Biyang Sag, Nanxiang Basin, eastern China. Oil physical property data and biomarkers show that these biodegraded oils occur only above burial depth equivalent to about 62 °C. This is much cooler than the cutoff temperature of biodegradation (about 80 °C), which has been interpreted within a complex petroleum evolution history that includes an early oil filling, significant uplift, a second phase of filling, and late-stage biodegradation.We use a new combination of fluid-inclusion analysis and calcite LA-ICP-MS U–Pb dating to obtain a temporal constraint on oil migration in the siliciclastic reservoirs. Two generations of oil inclusions, each showing a distinct fluorescence color (yellow and blue-green), were trapped before and after quartz cementation, respectively, which indicates multi-stage oil charge events. The early oil charge, marked by hydrostatic conditions and low-salinity pore waters, occurred during the late Eocene to early Oligocene burial period, corresponding to peak oil generation by basin modeling. The reservoirs were then refilled at a moderate-overpressure regime by higher maturity oils accompanied by high-salinity waters during the early Miocene exhumation. Reservoir sandstone-hosted, yellowish calcite veins, characteristic of 13C depletion and oil odor, contain primary blue-green fluorescent oil inclusions and bitumens, consistently pointing to precipitation from petroleum-derived fluids. LA-ICP-MS U–Pb dating of these vein calcites yields a U–Pb age of 19.6 ± 1.2 Ma, representing the latest timing of the second oil charge event in the North Slope. The isotope age of the fissure calcites near fault zones coincides well with the indirect age estimate based on fluid-inclusion homogenization temperature and the regional uplift stage. This scenario suggests that the Miocene tectonic compression not only triggered the recharge of oils but also facilitated the initiation or re-activation of faults that acted as conduits for oil migration.Reconstructed burial models show a continuous burial followed by significant uplift and erosion in this region. Since some reservoirs with maximum paleotemperature less than 80 °C were not sterilized during burial, the contained oils suffered from extensive biodegradation, presumably during the middle Miocene to present day. Thus, the shallower shutoff depth of biodegradation in this region was most likely ascribed to the paleo-pasteurization during burial, as opposed to later fresh oil replenishment or influx of shallow aquifers.

Unraveling the early petroleum migration of the Potiguar Basin, Brazil: Constraints from fluid inclusions of the Ubarana and Lorena oilfields

A coupled study of fluid inclusions and one-dimensional basin modeling allowed the reconstruction of the early hydrocarbon filling history of the main petroleum systems of the Potiguar Basin, Brazil. Confocal laser scanning microscopy, microthermometry and fluorescence spectra measurements were used to model PVTx properties of petroleum inclusions in samples from the onshore Lorena and the offshore Ubarana oilfields. The fluid inclusion data and basin modeling suggest that the initial filling of the Lorena reservoir (Pendência Formation) occurred during the rift stage in two scenarios at 62.7–80.6 °C (11–16.8 MPa): (i) the late rift phase in the Barremian–Early Aptian (ca. 129–124 Ma) or during the beginning of the uplifting phase in the Aptian (ca. 118–117 Ma). In the Ubarana Oilfield, hydrothermal fluids migrated alongside petroleum during the reservoir initial filling. Fluid inclusion homogenization temperatures for both the Açu (mode interval of homogenization temperatures, Th(LV→L)mode interval = 124–128 °C) and Ponta do Mel (Th(LV→L)mode interval = 115–130 °C) formations are higher than the present-day reservoir temperature (110 °C). Isochoric modeling of saddle dolomite-hosted fluid inclusions from the Ponta do Mel Formation indicates trapping temperatures between 128.9 and 133.1 °C and pressures between 10.6 and 12.9 MPa. Temperatures and salinities (16 and 20 mass % equivalent in NaCl + CaCl2) of aqueous inclusions hosted in saddle dolomite are similar to those of the fluid inclusions trapped in hydrothermal minerals in Mississippi Valley-Type Pb–Zn deposits. No specific timing can be suggested for the hydrothermal event in Ubarana Oilfield. However, this atypical (hydrothermal) petroleum system could be linked to two possible scenarios: (i) the onset of petroleum migration of the Alagamar Formation during the Cenozoic Macau (ca. 48–8.8 Ma) magmatic event; or (ii) an earlier activity of the petroleum system, prior to the peak oil generation (50–10 Ma).

Oil characteristics and source rock potential of Abu Rudeis-Abu Zenima area, Central province, Gulf of Suez, Egypt

The Gulf of Suez region is one of the most important petroleum provinces in Egypt and the Abu Rudeis-Abu Zenima area (ARAZ) located in the central province of the Suez Gulf on the eastern side. The scope of the current work is to evaluate the oils in the ARAZ area to identify oils characteristics and source rock potential using the data of whole oil gas chromatography and gas chromatography-mass spectrometry (GC-MS), in addition to stable carbon isotope analysis and vanadium and nickel contents. The bulk oils composition in ARAZ area characterized by moderate saturates and aromatics contents, high sulfur and NSO &asphaltene contents and heavy and normal API gravity. The composition of oils differs primarily due to their degree of thermal maturity. The oils generated from algal marine material with little terrestrial materials deposited under anoxic depositional conditions suggested by a low Pristane/Phytane (Pr/Ph) ratio. Moreover, the oils generated from carbonate source rocks of Thebes and Duwi rock units indicated by high C31-C35 Hopanes (45-50%) and C35/C34 extended Hopane ratio (0.99 – 1.12). The oils reached the peak-oil generation stage (0.85% Ro) indicated by the sterane isomerization ratio (20S % C29) that is less than 55 %. The oils of ARAZ area are matched the oils of the Gulf of Suez.