Oil Generation Research Articles

Hydrocarbon Accumulation and Overpressure Evolution of the Ordovician Carbonate Reservoirs in the Tahe Area, Tarim Basin, NW China

The recovery of reservoir paleo-pressure has been a key focus in hydrocarbon accumulation research. The evolution of paleo-pressure in carbonate reservoir rocks has long been a research challenge for researchers. Using the Tahe area in the Tarim Basin as a case study, this paper proposes an idea for studying the paleo-pressure evolution in carbonate rocks through fluid inclusions. A series of methods, including cathodoluminescence, fluid inclusion petrography, laser in situ U–Pb isotope dating, and microthermometry, were employed to determine the stages of hydrocarbon accumulation. Additionally, the paleo-pressure of oil inclusions from different stages has been restored, and the pressure evolution of the Ordovician carbonate reservoirs in the Tahe area was reconstructed. The study identifies four stages of oil charging in Ordovician carbonate reservoirs. The four oil-charging events occurred during the Caledonian (459–450 Ma), Hercynian (320–311 Ma), late Indosinian (227–213 Ma), and Yanshanian (134–117 Ma) periods. The overpressure evolution indicates that the Cambrian source rocks reached the first oil generation peak and started to expel hydrocarbons during the late Caledonian period. Oil mainly migrated vertically along strike-slip faults and accumulated in fracture-cavity karst reservoirs. At the same time, the reservoir pressure increased rapidly. Subsequent tectonic compression caused uplift and erosion, leading to the destruction of the oil reservoirs and a decrease in pressure. During the Hercynian period, hydrocarbons migrated and accumulated in reservoirs, leading to an increase in reservoir pressure. Subsequently, a slight formation uplift occurred, which caused a decrease in pressure. During the late Indosinian period, the third stage of oil accumulation led to an increase in reservoir pressure. Tectonic uplift during the Yanshanian period caused reservoir destruction and adjustment, resulting in a decrease in pressure. Reservoir pressure increased with oil charging during the Yanshanian period. Subsequently, a large number of faults developed in the study area, causing further destruction and re-adjustment of the oil reservoirs, which led to a decrease in pressure to the current state of normal pressure or weak overpressure.

Multifractal Methods in Characterizing Pore Structure Heterogeneity During Hydrous Pyrolysis of Lacustrine Shale

By using gas physisorption and multifractal theory, this study analyzes pore structure heterogeneity and influencing factors during thermal maturation of naturally immature but artificially matured shale from the Kongdian Formation after being subjected to hydrous pyrolysis from 250 °C to 425 °C. As thermal maturity increases, the transformation of organic matter, generation, retention, and expulsion of hydrocarbons, and formation of various pore types, lead to changes in pore structure heterogeneity. The entire process is divided into three stages: bitumen generation stage (250–300 °C), oil generation stage (325–375 °C), and oil cracking stage (400–425 °C). During the bitumen generation stage, retained hydrocarbons decrease total-pore and mesopore volumes. Fractal parameters ΔD indicative of pore connectivity shows little change, while Hurst exponent H values for pore structure heterogeneity drop significantly, indicating reduced pore connectivity due to bitumen clogging. During the peak oil generation stage, both ΔD and H values increase, indicating enhanced pore heterogeneity and connectivity due to the expulsion of retained hydrocarbons. In the oil cracking stage, ΔD increases significantly, and H value rises slowly, attributed to the generation of gaseous hydrocarbons further consuming retained hydrocarbons and organic matter, forming more small-diameter pores and increased pore heterogeneity. A strongly negative correlation between ΔD and retained hydrocarbon content, and a strongly positive correlation with gaseous hydrocarbon yield, highlight the dynamic interaction between hydrocarbon phases and pore structure evolution. This study overall provides valuable insights for petroleum generation, storage, and production.

Pore formation and evolution mechanisms during hydrocarbon generation in organic-rich marl

Marine organic-rich marl is not only a high-quality hydrocarbon source of conventional oil and gas, but also a new type and field of unconventional oil and gas exploration. An understanding of its pore structure evolution characteristics during a hydrocarbon generation process is theoretically significant and has application prospects for the exploration and development of this special type of natural gas reservoirs. This study conducted thermal simulation of hydrocarbon generation under near-geological conditions during a whole process for cylinder samples of low mature marine organic-rich marl in the Middle Devonian of Luquan, Yunnan Province, China. During this process, hydrocarbon products at different evolution stages were quantified and corresponding geochemical properties were analyzed. Simultaneously, field emission scanning electron microscopy (FE-SEM) and low-pressure gas adsorption (CO2, N2) tests were applied to the corresponding cylinder residue samples to reveal the mechanisms of different types of pore formation and evolution, and clarify the dynamic evolution processes of their pore systems. The results show that with an increase in temperature and pressure, the total oil yield peaks at an equivalent vitrinite reflectance (VRo) of 1.03% and is at the maximum retention stage of liquid hydrocarbons, which are 367.51 mg/g TOC and 211.67 mg/g TOC, respectively. The hydrocarbon gas yield increases continuously with an increase in maturity. The high retained oil rate at the peak of oil generation provides an abundant material basis for gas formation at high maturity and over-maturity stage. The lower limit of VRo for organic matter (OM) pore mass development is about 1.6%, and bitumen pores, organic-clay complex pores together with intergranular pores, grain edge seams and dissolution pores constitute a complicated pore-seam-network system, which is the main reservoir space for unconventional carbonate gas. Pore formation and evolution are controlled synergistically by hydrocarbon generation, diagenesis and organic-inorganic interactions, and the pattern of pore structure evolution can be divided into four stages. A pore volume (PV) and a specific surface area (SSA) are at their highest values within the maturity range of 1.9% to 2.5%, which is conducive to exploring unconventional natural gas.

Evolution of mechanical properties of organic-rich shale during thermal maturation

Accurate assessment of the mechanical properties of organic matter, clay matrix, and bulk shale during maturation remains a challenge. Here, we aim to assess the mechanical properties of organic-rich shale during maturation using a combination of nanoindentation methods and various geochemical analyses, i.e., mineral composition, mass loss rate, chemical structure of organic matter, and Rock-Eval analyses. Results show that the evolution of mechanical properties of organic matter in shale during maturation can be divided into: the main oil-generation stage, and the condensate oil and gas generation stage. The stiffening of organic matter in the shale is mainly due to increased aromaticity and condensation of aromatic groups. The clay matrix experiences a slight decrease in hardness and Young’s modulus at low maturity levels due to the generation of liquid hydrocarbons. However, overall, the clay matrix becomes stiffer as the shale matures due to shale dehydration, expulsion or cracking of liquid hydrocarbons, transformation of clay minerals, and hardening of organic matter. The Young’s modulus and hardness of bulk shale generally increase with increasing maturity. This is closely related to the hardening of organic matter and clay matrix, as well as the development of the more compact and dense microstructure in the shale.

Efficient selective hydrogenation of phenylacetylene over Pd-based rare earth dual-atomic catalysts

Selective hydrogenation of phenylacetylene to styrene plays a vital role in fine chemical synthesis with palladium (Pd)-based catalysts as the active components and usually suffered from low selectivity due to over-hydrogenation and low stability through polymerization (c.a. green oil generation). In this work, we found that by confining the Pd atom within a Pd-Ln (Ln: rare earth elements, such as Y, Lu, etc. ) diatomic structure [diatomic catalyst (DAC)], the reaction performance of selective hydrogenation of phenylacetylene has been greatly promoted, in which 92% styrene selectivity has been determined at 100% phenylacetylene conversion. This would be attributed to the diatomic structure established, which was achieved by introducing Pd-Ln precursors and confirmed by high-angle annular dark-field scanning transmission electron microscopy (HAADF-STEM) and X-ray adsorption fine structure (XAFS) characterizations and it was demonstrated that slight electron transfer from Ln to the adjacent isolated Pd makes it slightly negatively charged and facilitated the styrene formation. Besides, a Langmuir-Hinshelwood model was established to describe the whole reaction mechanism. After a systematic kinetic investigation, it suggests that the C8H6* + H* elementary step is probably the kinetically relevant for the whole reaction and the surface of the catalyst is mainly covered by C8H6*. The energy relationship of each step along phenylacetylene hydrogenation was quantitatively described by means of parity fitting and gas isothermal adsorption, providing insights into the selective hydrogenation of phenylacetylene over 0.02%Pd-Ln/C (Ln = Y/Lu) catalysts and pave the way of catalytic design at the atomic level.

Petroleum evolution and its genetic relationship with the associated Jinding Pb[sbnd]Zn deposit in Lanping Basin, Southwest China

The spatial association of hydrocarbons with metalliferous ore deposits is found worldwide and is particularly common to MVT PbZn deposits. Heavy oil and bitumen are found in the Jinding PbZn deposit within the Lanping Basin, South China. However, the temporal and genetic associations between hydrocarbons and the deposit are still controversial. To this end, integrating Raman analysis, ReOs geochronology and transmission electron microscopy analysis of the bitumen and in situ S isotope analyses of the sulfide, the petroleum evolution of the Jinding reservoir and its genetic relationship with the PbZn deposits were discussed. Bitumen ReOs data from this study and published works indicate that the late Triassic shales underwent two distinct oil-generation events before mineralisation (∼25 Ma), with initial oil generation occurring during the early Cretaceous (∼116 Ma) and the second during the early Paleogene (ca. 68–59 Ma). These two ages agree with the modelled thermal history of the Jinding reservoir. Combining the oil-before-ore timing sequence, high metal abundance of the bitumen, two negative sulfur isotope peaks of the sulfide and high S/C atomic ratio of the bitumen from the Jinding deposit, the oil-containing aqueous solutions were considered as one metal carrier during the hydrocarbon migration and accumulation; further, bacterial sulfate reduction and thermo-chemically induced sulfate reduction processes could have participated in the supply of reduced sulfur for the PbZn deposit precipitation.

Organic geochemical characterization and hydrocarbon generation modeling of Paleozoic-Paleogene shales, Wadi Sirhan basin, south-eastern Jordan

The Wadi Sirhan Basin in Jordan originated from the Arabian Platform and served as a stable shelf during the Paleozoic era. The Lower Paleozoic-Eocene sequence in the Wadi Sirhan Basin contains numerous shales, found, in ascending order the Upper Ordovician Dubeidib, Lower Silurian Mudawwara, Maastrichtian Ghareb, Paleocene Taqiyeh, and Eocene Sara fms. These strata warrant investigation of their source-rock potential and hydrocarbon generation modeling, to precisely elucidate the timing of petroleum generation. To achieve this, datasets were utilized from various analytical approaches, including Rock-Eval pyrolysis, visual kerogen analysis, pyrolysis-GC, and lipid biomarker geochemistry. The aim of this study is to assess these source rocks regarding organic matter quantity and quality, paleoenvironmental implications, thermal maturity, and petroleum generation depth/time. The Lower Paleozoic Dubeidib and Mudawwara shales are identified as effective source rocks, containing kerogen types II, II-III, and III. A high proportion of well-preserved, weakly fluorescent amorphous organic matter suggests an origin from marine plankton-derived alginite in an oxygen-deficient setting. These formations reached the peak oil window during the Devonian (∼405-380 Ma) and Carboniferous (∼320-300 Ma). The Dubeidib Fm experienced late-stage oil generation during the Early Triassic (∼255-250 Ma), with a transformation ratio (TR) of 68%. The Ghareb Fm predominantly contains type II kerogen, while the Taqiyeh and Sara fms mainly contain type I kerogen with minor type II kerogen. Thermal maturity assessments using integrated parameters indicate that the Dubeidib and Mudawwara shales have entered the main phase of hydrocarbon generation, while the Ghareb, Taqiyeh, and Sara shales remain immature. Furthermore, analysis of biomarker ratios reveals the dominance of marine over terrestrial organic matter in the studied strata. These clay-rich sediments were deposited under reducing conditions, which further facilitated the rearrangement of steranes into diasteranes. The modeled TRs indicate the generation and subsequent expulsion of hydrocarbons, but the absence of suitable reservoirs and/or improper trapping system, owing to the major Hercynian unconformity, led to an incomplete petroleum system in the basin. Additional investigation is required to evaluate the potential of the Early Paleozoic shales as subsurface unconventional resources, considering parameters such as brittleness index and hydraulic fracturing. This study holds important implications for future hydrocarbon exploration and development in the Wadi Sirhan Basin. The insights gained from such investigations could help mitigate the risk of petroleum exploration failures in the Wadi Sirhan Basin, guiding future exploration and development efforts towards promising approaches.

Organic geochemistry and 1D-basin modeling in the Taranaki Basin, New Zealand: Implications for deltaic-source rocks of the cenozoic oil and condensate reservoirs

The Taranaki Basin in New Zealand is an area of active exploration for oil and condensate. This research focuses on integrating geochemical characteristics and 1-D basin modeling to Late Cretaceous to Miocene source rock systems, along with oil and condensate data from fifty-seven wells in the Taranaki Basin. The geochemical study reveals that the oil and condensate samples were generated from clay-rich source rocks, containing mixed organic matter, with large amounts of terrestrial organic matter input. These source rocks were deposited in fluvial to fluvio-deltaic environments under oxic conditions. The presence of oleanane in both oil and condensate samples suggests that the source rocks had a significant terrestrial component and deposited during the Late Cretaceous to Cenozoic. Using various biomarker proxies, oil-source rock correlation along with 1-D basin modeling revealed that the oil and condensate were mainly derived from the Late Cretaceous Rakopi and Paleocene Farewell formations at different maturity stages. The oils were generated within the peak-mature oil window, while the condensates primarily resulted from the secondary cracking of oil taking place in the source rock within the gas generation window. This finding is consistent with the 1-D basin modeling results. The model shows that the Paleocene Farewell source rock has achieved the primary stage of oil generation (0.55–0.95 Easy %Ro), contributing to most of the discovered oils in the Cenozoic reservoir rocks. Meanwhile, the Late Cretaceous Rakopi source rock reached the gas window with a higher vitrinite reflectance of more than 1.30 Easy %Ro, indicating greater gas generation potential.

Evaluation of waste plastic and waste cooking oil as a potential alternative fuel in diesel engine

The generation of plastic waste and waste cooking oil is a serious environmental concern because of worldwide waste disposal issues. At the same time, increasing demand and contemporary geopolitics make fossil fuels a significant worldwide problem. As a result, there has been an increase in demand for alternate fuel for CI engines. To overcome these twin problems can be addressed by converting waste into liquid fuels. This research explores an intriguing area by mixing waste cooking oil biodiesel and waste plastic oil to create a mixture that remarkably seems like the physico-chemical properties of diesel fuel in a society that is looking for sustainable alternatives. So, in this investigation, a ternary fuel blend of Petro-diesel, waste cooking oil biodiesel (WCOB), and waste plastic oil (WPO) was used in the diesel engine. To enhance the properties of fuel, combustion, emission, and performance parameters of diesel engines, a ternary blend of B20P20D60 was employed in the CI engine as an alternative fuel. In the ternary fuel blends, WCOB, WPO, and diesel content were 20%, 20%, and 60%, respectively. The results were compared with conventional diesel fuel, showing that the ternary fuel blend B20P20D60 has an improved brake thermal efficiency of up to 1.71% at 80% loading and reduced emissions (HC, CO, NOx) compared to conventional diesel. Because of this, the ternary blends have significant potential for use in diesel engines.

Oil and Gas Content of the South Caspian Basin

Abstract —We have compiled maps of areal isotope composition changes and constructed graphs of gas HC distribution depending on the stratigraphic age of the host rocks and graphs of isotope composition changes depending on the depth of sampling to study the hydrocarbon potential of the deep-seated oil and gas pools of the South Caspian Basin. The genesis of gas was studied using the techniques elaborated by M. Schoell and A. James. Two stages of hydrocarbon formation have been established by study of various kinds of gas manifestation. The first stage (Miocene–Eocene) began in the deposits underlying the Productive Series and continued up to the deposits of the latter. This stage was characterized by a frequent change in the directions of both downward and upward movements of gases. The second stage of hydrocarbon formation (Anthropogene–Pliocene) began in the deposits of the Productive Series and was characterized by a change in the regional geodynamic setting. Avalanche sedimentation and the predominance of downward movements over upward ones favored the accumulation of thick sediments at the time when the Productive Series formed. The sedimentation and tectonic processes (downwarping) in the deep-water zone of the basin led to harsh thermobaric conditions in the sedimentary strata. A detailed analysis of the results of gas survey in the deep-water zone of the South Caspian Basin has shown gas generation with a predominance of two components, methane and ethane. Study of the trends of temporal and areal hydrocarbon migration and of the areas of oil and gas generation makes it possible to reveal structures with evidence for large and giant hydrocarbon reserves. We have established that gas hydrocarbons in the bottom and upper-section sediments of the southern Caspian Sea are intimately related to the sources of hydrocarbons, their migration, and other processes running in the deep-seated sediments and in the upper section.

Differential hydrocarbon generation characteristics of organic matter with green algae and cyanobateria origins in the Permain Lucaogou Formation of the Santanghu Basin

Organic-rich fine-grained rocks are key carriers of unconventional oil and gas resources, making it crucial to understand their hydrocarbon generation and evolution characteristics. This study examines the fine-grained rocks of the second member of the Lucaogou Formation (P2l2) in the Tiaohu and Malang Sags of the Santanghu Basin, focusing on how different organic matter (OM) backgrounds - primarily green algae and cyanobacteria - affect hydrocarbon generation and crude oil properties. Kinetic analysis and hydrous pyrolysis experiments on shales rich in green algae, cyanobacteria, and their mixtures revealed that green algae - derived OM requires lower activation energy to initiate hydrocarbon generation, results in an earlier oil generation peak, and has a broader oil window. Conversely, cyanobacteria - derived OM needs higher activation energy to start hydrocarbon generation, has a later oil peak, and a more concentrated generation period. These findings led to two models: the "green algae origin - early hydrocarbon generation - early oil peak - broad oil window model" and the "cyanobacteria origin - late hydrocarbon generation - late oil peak - concentrated oil generation model." Correlation analysis showed that aromatic hydrocarbons, resins, and asphaltenes significantly degrade crude oil quality. Hydrous pyrolysis experiments indicated that the heavy component content (aromatic hydrocarbons + resins + asphaltenes) in liquid hydrocarbons follows the order: residual oil > absorbed oil > expelled oil, with content initially increasing and then decreasing with maturity, and the color change of liquid hydrocarbons in dichloromethane reflects heavy component content changes effectively. Calculations of density and viscosity of liquid hydrocarbons, based on heavy component content and crude oil properties, were compared with the longitudinal distribution of crude oil properties in the study area. Results show that the hydrocarbon generation characteristics of green algae and cyanobacteria control crude oil properties, highlighting significant intra-source differentiation in the P2l2 shale and validates the phase separation approach in hydrous pyrolysis experiments. The P2l2 shale, with its high OM content and substantial hydrocarbon generation, holds great potential for shale oil exploration, but both reservoir quality and crude oil property evolution under different OM backgrounds should be considered when selecting favorable areas.

The effect of temperature during plasma nitriding on the properties of IN718 additively manufactured by laser beam powder bed fusion

The IN718 superalloy has become a strategic alloy for applications in critical components in aerospace, oil, and gas, or power generation. Commercially, IN718 is produced by conventional casting processes. However, manufacturing is evolving towards 3D printing, which allows the manufacturing of near-net-shape parts and complex designs, thus optimizing manufacturing steps, reducing production costs, and adding other advantages to the final product. However, high corrosion resistance and mechanical strength are required in applications such as oil and gas, whereas IN718 superalloys have limitations. Surface hardening by applying plasma nitriding can protect against corrosion by increasing mechanical strength and wear resistance. For this, plasma nitriding has been widely applied for surface hardening of IN718; however, little is found on the effects of surface treatments (coating or nitriding) of additively manufactured alloys. The effects of temperature during plasma nitriding on the surface properties of IN718 superalloy 3D printed by the Laser Beam Powder Bed Fusion (LB-PBF) method are reported here. Samples of IN718 fabricated by 3D printing were plasma nitrided at fixed temperatures between 500 and 650 °C in a semi-industrial reactor, their effects are analyzed and correlated with their microstructural characteristics, the mechanical properties at the micro- and nanoscale, and the tribological responses in a pin-on-disk configuration.

Effects of organic richness, mineral composition, diagenesis, and thermal maturity on the viscoelastic properties of organic-rich Cretaceous mudstones in the Middle Magdalena Valley basin, Colombia

A major geological risk factor for engineering and energy-related applications, such as CO2 storage and unconventional hydrocarbon production, is the geomechanical integrity of mudrocks. The goal of this work is to better constrain the macroscopic mechanical properties resulting from microstructural components by investigating the effects of thermal maturity, mineral composition, diagenesis and organic richness on the mechanical properties of Cretaceous mudstones in two surface sections (San Vicente de Chucurí and La Cristalina Creek) and one well (La Luna-1) from the Middle Magdalena Valley Basin (MMVB), Colombia. The thermal maturity of 22 rock samples was evaluated via organic source-rock screening and determination of illite crystallinity (Reichweite). Both geothermometers placed the La Luna Formation rock samples from San Vicente de Chucurí and the La Luna-1 well within the oil generation window (80°C–120 °C). In contrast, the rock samples of the Guaguaquí Group from La Cristalina Creek in the southern part of the basin are within the gas window (>180 °C). The mineralogy of organic-rich mudstones in the MMVB is dominated by quartz and calcite. Moreover, mudstones from the MMVB have a wide range of organic richness and clay contents, with organic abundances comparable to and clay contents lower than those found in other source-rock reservoirs. The Young's modulus (EIT), Martens hardness (HM), and creep (CIT), as determined through microindentation experiments, highly varied, but overall, the findings suggest that the Cretaceous rocks of the MMVB present conditions favorable for hydraulic fracturing. Furthermore, the viscoelastic properties of Cretaceous rocks in the MMVB are influenced primarily by the concentrations of strong minerals (quartz and calcite) and weak components (clay and TOC). Specifically, an increase in the concentration of weak components compared with that of strong minerals leads to an increase in CIT and a decrease in HM and EIT, and vice versa. Unlike other source-rock reservoirs, there are no indications of a strong correlation between thermal maturity and mechanical properties, suggesting a decoupling of these parameters in rocks of the MMVB. A close scanning electron microscopy examination of the rocks indicated that the observed weak to moderate correlation between thermal maturity and mechanical properties appears to result from rock silicification and calcite cementation caused by the precipitation of these minerals at early stages of diagenesis. This observation implies that the impact of diagenesis on rock geomechanics of silica-rich and calcareous-rich mudstones may override or be more important than the effects of thermal maturity, which, along with clay and organic matter contents, are the greatest controls in the geomechanics of argillaceous source-rock reservoirs.

Shale Oil Generation Conditions and Exploration Prospects of the Cretaceous Nenjiang Formation in the Changling Depression, Songliao Basin, China

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part.

Comparative assessment for biodiesel production from low-cost feedstocks of third oil generation

Biodiesel offers a sustainable fossil fuel alternative, highlighting the importance of third-generation feedstocks like macroalgae and waste frying oils (WFO) from palm, sunflower, and corn. This study investigates their physicochemical properties using different feedstocks towards biodiesel standard specifications. The feedstocks were synthesised through transesterification process at operating parameters molar ratio of methanol to oil (3:1–12:1), catalyst concentration (0.5–3 wt %), reaction time (60–240 min), and reaction temperature (55–75 °C). The fatty acid compositions were analysed using GC-Fid shows Azolla filiculoides (54.0 %), Ulva lactuca (56.0 %), WFO palm (56.5 %), WFO sunflower (85.7 %) and WFO corn (82.7 %) biodiesels dominated by unsaturated fatty acids have good physicochemical properties such as densities (872–883 kg/m3), kinematic viscosities (3.52–5.3 mm2/s), cloud points (10 °C to −10 °C), pour points (8 °C to −12 °C), cetane numbers (44.4–57.9), heating values (38.60–41.68 MJ/kg), and iodine values (60.94–129.15 g I2/100 g) meet the specification of biodiesel standards. This study reveals fatty acid profiles significantly impact the physicochemical properties of biodiesel. Among all feedstocks, Azolla filiculoides demonstrating particularly promising characteristics for biodiesel production. These findings advocate for the increased exploration of third-generation feedstocks in the quest for sustainable biodiesel production processes.

The Impact of Fractures on Shale Oil and Gas Enrichment and Mobility: A Case Study of the Qingshankou Formation in the Gulong Depression of the Songliao Basin, NE China

To study the impact of faults on the enrichment and mobility of shale oil in the Gulong area, representative rock samples were selected in this paper. Based on geochemical data and chemical kinetics methods, coupled with shale oil enrichment and mobility analysis techniques, the shale oil generation quantity and in situ oil content were evaluated from the perspectives of shale oil generation and micro migration, and the mobility of shale oil was revealed. At the same time, the hydrocarbon expulsion efficiency (HEE) of shale was qualitatively and quantitatively characterized, combined with the development of faults. The research results indicate that the study area mainly develops organic-rich felsic (ORF)/organic-containing felsic (OCF) shale, their proportion in both wells exceeds 65%, and the resource amount is the largest in this type of lithofacies. The development of a fault controls the enrichment of shale oil, and the in situ oil content and oil saturation index (OSI) of the shale in well Y58, which is close to the fault, are significantly worse than those in well S2. Well Y58 has 9.52 mg/g and 424.83 mg/g TOC respectively, while well S2 has 11.34 mg/g and 488.73 mg/g TOC respectively. The fault enhanced the migration of shale oil, increasing the efficiency of oil expulsion. As a result, the components with weak polarity or small molecules, such as saturated hydrocarbons and low carbon number n-alkanes, are prone to migration, reducing the mobility of shale oil.

New Advance in the Study of Shale Oil Generation Peak Determination and Diagenetic Pore Evolution

Shale formations globally are widely distributed with abundant resources and varied thermal maturation ranges. However, the understanding of shale’s oil generation peak, diagenetic stages, and pore evolution remains incomplete. This study investigates shale samples of varying maturities and organic matter content from representative oil and gas basins in China and the United States. Comprehensive characterization was conducted using thermal simulation, rock X-ray diffraction analysis, N2 and CO2 adsorption, and mercury injection analysis. The study delineates the hydrocarbon generation process in shale, identifies the oil generation threshold, determines the peak oil generation, and categorizes shale’s diagenetic stages based on clay minerals and pore evolution. The results indicate: (1) highly mature shale exhibits delayed hydrocarbon expulsion and peak oil generation, starting at Ro values greater than 0.75% and reaching peak oil generation at Ro levels surpassing 1.2%. In contrast, peak oil generation in less mature shale initiates at Ro values of 1.1%, providing a more precise depiction of the shale’s diagenetic evolution stages; (2) the higher the TOC content of shale, the greater its hydrocarbon generation capacity, showing a robust positive correlation between hydrocarbon generation and TOC; (3) the diagenesis and pore evolution of shale can be categorized into four distinct stages: the early diagenesis stage (Ro < 0.5%), dominated by mesopores, and with reduced pore volume and surface area; the middle diagenesis stage A (0.5%–1.1%), where shale pore volume has been enhanced while the surface area has been reduced; the middle diagenesis stage B (1.1%–2.0%), where an initial decrease followed by an increase in mesopore volume occurs, along with a modest increase in macropores; and the late diagenesis stage (Ro > 2.0%), with increased organic pores and microfractures, while both pore volume and surface area expand. The study suggests that a Ro of 1.1% marks the peak oil generation period for shale, occurring during the early stage of middle diagenesis, characterized by larger pore volume and surface area, crucial for shale oil and gas enrichment.

The Implications of Seeping Hydrocarbon Gases in the Gunsan Basin, Central Yellow Sea, off the Southwest of Korea

A detailed analysis of high-resolution (3.5 kHz) chirp seismic profiles acquired in the Gunsan Basin of the central Yellow Sea revealed that hydrocarbon gases are actively seeping via the formation of many plumes. The uppermost sedimentary layer was acoustically confirmed to be fully or partially charged with gases. Somewhat favored by the low-tide period, episodic gas seepage is mainly associated with the underlying fault systems of Cretaceous-Cenozoic sedimentary strata in the southwestern part of the basin. Catastrophic gas expulsion seems to have formed a crater at the sidewall of a sedimentary ridge and two diapirs. Here, methane is poorly concentrated but rich in the heavy carbon isotope (δ13C, −52.6‰ to −44.7‰ The Vienna Peedee Belemnite [VPDB]), indicating that methane formed mainly through biodegradation of heavy oils at depth remains in the shallow sediments following its expulsion. Episodic rapid upward advection of porewater is also manifest by unmixed heavy methane trapped in the upper part of the primary biogenic methane (δ13C, about −90‰ VPDB)-filled sediment core. These findings imply that the Gunsan Basin fulfills the requirements for possible generation and preservation of oil and gas, like the petroliferous basins of eastern China and the Yellow Sea.

Numerical and experimental study of energy absorption in multilayer tubes manufactured through spinning forming process under quasi-static axial loading

Currently, dual-layer tubes play a pivotal role in sectors like nuclear, oil, gas, and steam generation. Recent research focuses on enhancing energy absorption in these tubes using the spinning forming process. This thin-walled nature benefits their application as efficient energy absorbers in transportation like trains and aircraft. A novel approach integrates coarse and fine-threaded ridges between steel and aluminum layers to create a mechanical interlock using the spinning forming technique. This interlock enhances the bond through flow forming, resulting in robust dual-layer tubes. Interlayer connection strength is rigorously tested through shear tests, pre and post flow forming, indicating a significant post-flow forming enhancement. This process substantially bolsters the overall structural integrity of dual-layer tubes. In crush tests, both single-layer and dual-layer steel and aluminum tubes undergo pressing through flow forming. Comparative analysis of energy absorption parameters—specific energy and crushing percentage—reveals notable performance differences. An annealed version of the tube with an aluminum layer is also included due to prior aluminum layer failures. Among dual-layer samples, the flow formed variant with fine-threaded ribs exhibits superior energy absorption and bonding. Finite element simulation of the pressed dual-layer sample demonstrates an 8.42 % deviation between simulated and experimental energy absorption outcomes. The study highlights that tightly bonded layers result in enhanced bonding characteristics.

An integrated convolutional neural network prediction framework for in situ shale oil content based on conventional logging data

The quantification of total organic carbon (TOC) and the free hydrocarbon content (S 1 ) is crucial for evaluating the shale oil generation and bearing properties of source rocks. This study aimed to enhance the accuracy of TOC and S 1 quantification in shale oil evaluations. The scope encompassed the development of a novel deep learning framework to overcome the limitations of traditional physical and machine learning or deep learning methods. This paper proposes an integrated swarm optimization algorithm–convolutional neural network/machine learning framework. This framework uses a swarm optimization algorithm for the hyperparameter optimization of a convolutional neural network or machine learning framework, utilizing experimental data from core samples preserved in liquid nitrogen alongside well logging data. The application of the proposed framework to the H11 well in the Subei Basin, China, using 110 core samples, demonstrated a superior performance. The results validate the framework's effectiveness in predicting the TOC and S 1 contents at various depths. The proposed framework stands out for its convenient methodology, wide application range and high precision in prediction. These attributes contribute significantly to the field of petroleum engineering and development, offering a novel approach that promises to enhance both the efficiency and accuracy of well logging evaluation.