Mature Source Rocks Research Articles

Spatiotemporal Variation in Mature Source Rocks Linked to the Generation of Various Hydrocarbons in the Fuxin Basin, Northeast China

The assessment of highly mature source rocks linked to hydrocarbon generation remains a challenge in oil and gas exploration. However, substantial terrigenous influences and thermal variations have complicated the formation and evolution of source rocks. This study presents an integrated assessment of highly mature source rocks in the Fuxin Basin, based on sedimentological, geochemical, and organic petrological analyses. Two types of oil- and coal-bearing source rocks were deposited in the semi-deep lake and shore–shallow lake facies during the Jiufotang and Shahai periods. The development of source rocks migrated eastward alongside the lacustrine depocenter, influenced by basin evolution related to extensional detachment tectonism. Furthermore, a gradual increase in thermal records was detected from the western to eastern basins. Consequently, thermal decomposition of source rocks in the Jiufotang formation reduced the organic matter (OM) abundance in the central and eastern basins. Meanwhile, OM types of source rocks range from kerogen type-II1/-I to type-II2/-III, with intense hydrogen generation observed from the western to eastern basins. Consequently, the quality and hydrocarbon accumulation of source rocks are influenced by sedimentation and thermal maturity variation. The spatiotemporal variation in mature source rocks enhances the potential for exploring conventional petroleum, coalbed methane, and shale gas across different strata and locations. Our findings illustrate the significance of the sedimentary and thermal effects in characterizing the evolution of highly mature source rocks, which is relevant to determine oil and gas exploration in similar geological settings.

Evaluation of uranium migration during the maturation of hydrocarbon source rocks.

The source of uranium is an important research topic related to the exploration of sandstone-type uranium deposits, and potential uranium sources in deep basins are often overlooked. Black organic-rich shale is a common uranium-bearing rock in deep sedimentary basins. However, relatively few studies have investigated the migration of uranium during hydrocarbon generation in and release from uranium-rich shale. In this study, the uranium-rich shale in the Chang 7 member of the Yanchang Formation of the Upper Triassic in the Ordos Basin was selected to investigate the migration of uranium and other trace elements during the thermal maturation of uranium-rich shale via a semiopen pyrolysis simulation system. The gas and liquid products as well as the solid residue were thoroughly analysed by means of multiple instruments. The results showed that uranium significantly migrated before hydrocarbon generation (Ro < 0.61%), with a leaching rate between 12.1% and 18.8%. The leaching rate of uranium during the hydrocarbon generation stage (0.63% < Ro < 1.35%) was relatively low, ranging from 0 to 7.2%. Cu, Pb, Zn, Mo, and other trace elements also migrated considerably during the early stage of thermal evolution, with leaching rates ranging from 2.9 ~ 11.6%. The yield of low-molecular-weight organic acids (LOAs) was the highest in the early stage of thermal maturity, and the LOA yield exhibited a good correlation with the leaching rates of Cu, Pb, Zn, Co, Mo, etc. The generation of LOAs from source rocks was conducive to the leaching and migration of trace elements. Moreover, according to a statistical analysis of published geochemical data, the total organic carbon (TOC) content, uranium content, and U/TOC ratio in shale decreased significantly with increasing burial depth, indicating that uranium migrated significantly upon kerogen hydrocarbon generation during thermal evolution. Therefore, uranium-rich shale is an important deep uranium source in sedimentary basins.

Source rock and petrophysical evaluation of the Late Cretaceous Haymana Formation, Haymana Basin, Central Anatolia, Turkey

This study investigates the petroleum potential of the mudstones of the Late Cretaceous Haymana Formation in the Haymana Basin, Turkey. Lithofacies, pore structure, and source rock characteristics of the mudstones are examined using stratigraphical, sedimentological, petrophysical, and organic geochemical methods along four stratigraphic sections and other sampling sites. The depositional model presents a facies distribution within a submarine fan system. According to bulk mineralogy, the identified lithofacies are mixed mudstone, mixed siliceous mudstone, marl, mixed carbonate mudstone, argillaceous/siliceous mudstone, and clay-rich siliceous mudstone. XRD and mercury intrusion measurements suggest that the macropores (&gt; 50 nm) of the mudstones formed by dissolution of calcite, while mesopores (2 nm-50 nm) developed around the clay/quartz/feldspar. Of the analysed samples, no lithofacies class is distinct with any specific range of porosity or permeability, which suggests a strong heterogeneity in pore throat size, mineral content, and grain size. The black shale from the northwest of the basin with 1.19% TOC, 0.07 mg/g S 1 , 1.01 mg/g S 2 , and 441°C T max is a relatively more mature source rock although it still exhibits poor petroleum potential. Overall, the TOC values (avg. 0.38%) of the mudstones suggest organic-poor rock characteristics for the Haymana Formation in the studied parts of the Haymana Basin.

Evaluation of source rocks and prediction of oil and gas resources distribution in Baiyun Sag, Pearl River Mouth Basin, China

By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin, China, the development characteristics of hydrocarbon source rocks in the sag are clarified. Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type, scale, and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation. The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks, which are deposited in a slightly oxidizing environment. The source rocks are mainly composed of terrestrial higher plants, with algae making a certain contribution, and are oil and gas source rocks. Current geothermal field of the sag was reconstructed, in which the range of geothermal gradients is (3.5–5.2) °C/100 m, showing an overall increasing trend from northwest to southeast, with significant differences in geothermal gradients across different sub-sags. Baiyun Sag has undergone two distinct periods of extensional process, the Eocene and Miocene, since the Cenozoic era. These two periods of heating and warming events have been identified, accelerating the maturation and evolution of source rocks. The main body of ancient basal heat flow value reached its highest at 13.82 Ma. The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags. The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity, while the Eocene Enping Formation has reached the stage of maturity to high maturity. The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window. Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil, and has ability to generate kerogen cracking gas in the late stage. The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation. The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags, with an average of about 1 200×104 t/km2. Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3rd and 4th members of Wenchang Formation. Four favorable zones are selected for the division and evaluation of migration and aggregation units: No. ▪ Panyu 30 nose-shaped structural belt, No. ▪ Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt, No. ▪ gentle slope belt of Baiyun east sag, and No. ▪ Baiyun 1 low-uplift.

Evaluating the reliability of solid phase extraction techniques for hydrocarbon analysis by GC–MS

Saturate and aromatic compounds are essential in the petroleum industry for assessing the thermal maturity of source rocks and oils, which is critical for basin modeling and sweet-spot mapping. These compounds also play a role in environmental applications, such as oil spill fingerprinting and biogeochemistry. However, the analysis of these compounds by gas chromatography-mass spectrometry (GC–MS) requires meticulous and time-consuming separation processes. Traditional methods like normal-phase liquid column chromatography (LCC) involve large volumes of harmful solvents. This study evaluates the effectiveness of five different sorbents using solid-phase extraction (SPE) techniques—neutral Si, SiOH, Ag-ion, neutral Al, and Ag-ion mixed with activated silica—compared to LCC. The goal was to discern differences in peak resolution, concentration, and isomer ratios of saturate and aromatic compounds for thermal maturity and source rock assessments. The results show that SiOH, neutral Si, and neutral Al do not fully separate aromatic compounds from the saturate fraction, sometimes leaving 40–100% of aromatics within the saturate fraction. Ag-ion mixed with activated silica provided the best separation, resulting in up to 23 times higher aromatic concentration than SiOH. This method is more reliable for quantifying both saturate and aromatic compounds, increases the efficiency of hydrocarbon evaluations, and reduces solvent consumption by 63%, offering a more sustainable approach to hydrocarbon analysis.

Cretaceous and Cenozoic source rocks maturation modelling in the Gulf of Gabes, central Eastern Tunisia: estimation of hydrocarbon in place

Cretaceous and Cenozoic source rocks maturation modelling in the Gulf of Gabes, central Eastern Tunisia: estimation of hydrocarbon in place

Using benzonaphthothiophenes to trace paleo-oil migration directions in the Ediacaran-Cambrian reservoirs of the central Sichuan Basin

Benzonaphthothiophenes (BNTs) are important organosulfur compounds in oil, and their concentrations and [2,1]/([2,1] + [1,2])BNT ratio have been used as migration tracers. Here we focus on the applicability of BNTs as migration tracers for abnormally heat-altered paleo-oil reservoirs. For this purpose, 57 pyrobitumen samples from the Ediacaran to Cambrian dolomite reservoirs in the central Sichuan Basin were collected and detected by gas chromatography-mass spectrometry. The results showed that most pyrobitumens of the studied samples are characterized by high concentrations of unsubstituted polycyclic aromatic hydrocarbons (PAHs), high values of fluoranthene/PAHs, pyrene/PAHs, fluoranthene/(fluoranthene + pyrene), benzofluoranthene/(benzofluoranthene + benzopyrene), and unsubstituted-to-methylated aromatic ratios due to the alteration by abnormal heating. These pyrobitumens have high concentrations of BNTs, and their three isomers show a pattern of [2,1] > [1,2] > [2,3]BNT. The BNTs concentrations display a good positive relationship with the concentrations of the abnormal heating-related PAH, while [2,1]/([2,1] + [1,2])BNT ratio has no correlation with the abnormal heating-related indices, suggesting that abnormal heating of the paleo-oil reservoirs lead to the enrichment of BNTs but has a limited effect on [2,1]/([2,1] + [1,2])BNT ratio. Moreover, [2,1]/([2,1] + [1,2])BNT ratio seem to be not affected by kerogen type and depositional environment, but increases with source rock maturity. Therefore, the [2,1]/([2,1]+[1,2])BNT is still an effective migration tracer for abnormally heated reservoirs. This ratio was applied as migration tracer in the studied area. The result suggests that the paleo-oil primarily migrated from west depression to east bulges, followed by the direction from northwest to southeast, which is congruent with the geological setting and exploration practice, demonstrating the applicability of this parameter for abnormally heat-altered oil reservoirs.

Study on the Suppression of Vitrinite Reflectance: A Thermal Simulation Experiment.

Vitrinite reflectance is the most widely used parameter for reconstructing the thermal history of sedimentary basins and evaluating the maturation of source rocks. However, suppression of vitrinite reflectance has also been reported, which could affect the accuracy of evaluating the degree of thermal evolution. In this article, the influence of hydrocarbon generation on vitrinite reflectance during thermal evolution is studied based on thermal simulation experiments in a closed system. The results show that hydrocarbon absorption and overpressure can lead to the suppression of vitrinite reflectance. For R 0 values between 0.6% and 2.1%, the suppression of vitrinite reflectance is primarily attributed to the impregnation of the telocollinite texture with hydrocarbons generated from type I kerogen. At R 0 values exceeding 2.1%, overpressure becomes the dominant cause of the anomalous reflectance. Under closed-system conditions, the retention of volatile products within the pore network of vitrinite hinders the structural reorganization, leading to reflectance suppression.

A rigorous workflow and comparative analysis for accurate determination of vitrinite reflectance using data-driven approaches in the Persian Gulf region

Vitrinite reflectance (VR) is a critical measure of source rock maturity in geochemistry. Although VR is a widely accepted measure of maturity, its accurate measurement often proves challenging and costly. Rock–Eval pyrolysis offers the advantages of being cost-effective, fast, and providing accurate data. Previous studies have employed empirical equations and traditional machine learning methods using T-max data for VR prediction, but these approaches often yielded subpar results. Therefore, the quest to develop a precise method for predicting vitrinite reflectance based on Rock–Eval data becomes particularly valuable. This study presents a novel approach to predicting VR using advanced machine learning models, namely ExtraTree and XGBoost, along with new ways to prepare the data, such as winsorization for outlier treatment and principal component analysis (PCA) for dimensionality reduction. The depth and three Rock–Eval parameters (T-max, S1/TOC, and HI) were used as input variables. Three model sets were examined: Set 1, which involved both Winsorization and PCA; Set 2, which only included Winsorization; and Set 3, which did not include either. The results indicate that the ExtraTree model in Set 1 demonstrated the highest level of predictive accuracy, whereas Set 3 exhibited the lowest level of accuracy, confirming the methodology's effectiveness. The ExtraTree model obtained an overall R2 score of 0.997, surpassing traditional methods by a significant margin. This approach improves the accuracy and dependability of virtual reality predictions, showing significant advancements compared to conventional empirical equations and traditional machine learning methods.

Integrated seismic, petrophysical, and geochemical studies for evaluating the petroleum system of the Upper Bahariya-Abu Roash G sequence in the Karama Field, Abu Gharadig Basin, North Western Desert, Egypt

The main aim of this study is to delineate the hydrocarbon potential and evaluate the petroleum system elements of the Cenomanian Abu Roash G (AR/G) and the Upper Bahariya Members in the Karama Field. It lies at the southeast borders of the Abu Gharadig Basin, a well-known basin in the W.D. to the NE of Africa. We accomplish this study by analyzing a total of thirty 2D seismic profiles, a complete data set of well logs for five wells, and their geochemical data. The workflow starts with illustrating the dominant subsurface structural features, defining the main potential reservoirs and their parameters, and checking the maturity of the probable source rocks. The seismic interpretation indicated that the research area had been influenced by a NE-SW anticlinal structure accompanied by a set of WNW-ESE and NW-SE normal faults that are controlled by the positive compression inversion process that dominated during the Late Cretaceous. Analyzing and processing the well log data sets suggest that the reservoirs of the Abu Roash G (AR/G) and the Upper Bahariya Members are characterized by poor to good reservoir settings with net-pay thickness reaching up to 13–50 feet in the different wells (av. Effective porosity (∅eff) = 17.7 % and 15.6% for the AR/G and the Upper Bahariya Members, av. Shale volume (Vsh) = 17.4 % and 13.6 %, av. Water saturation (Sw) = 38.9 % and 39.8 %, while av. Hydrocarbon saturation values (So) = 60.2 % and 61.1%, respectively). The geochemical and maturity analyses assisted in determining the potential mature source rocks of the Jurassic Khatatba Shale (TOC = 0.70–5.67%; S1+S2 = 0.43–5.97 mg/g, Ro = 0.54–1.06 %) with some contribution from the Cretaceous sources (Alam El-Bueib and Bahariya Formations). Studying elements of the petroleum regime of the Karama Field indicates that the trapped hydrocarbons are structurally controlled by three-way dip closures, horst blocks, sealing faults, and vertical sealing by impervious shale and limestone beds. This case study could be applied to similar analogs in other oil fields in the Egyptian Western Desert to delineate their hydrocarbon potential and structural setting.

Petroleum source-rock characterization and the depositional environment of Kimmeridgian–Tithonian sequences, Jaisalmer Basin, western Rajasthan, India

In hydrocarbon exploration, total organic carbon (TOC) content and Rock-Eval pyrolysis are commonly employed geochemical techniques that offer concise insights into kerogen type, effective source-rock identification and thermal maturity. In the current study, the data obtained from Rock-Eval pyrolysis has been used to define the source-rock quality, generative potential, kerogen type, maturity of the source sediments and kerogen kinetics of the Baisakhi–Bhadesar Formation of Kimmeridgian–Tithonian (154.7–145.6 Ma) age. Basinal level hydrogen index (HI), TOC content, source-rock maturity, transformation ratio and heat-flow maps have been generated by integrating the data from pyrolysis with previously available data from wells drilled in the basin. The TOC content of the Kimmeridgian–Tithonian sequence ranges from 0.03 to 12.71% in the studied samples, with an average TOC content of 1.28%, indicating good source-rock quality. The HI, in collaboration with T max and vitrinite reflectance (VR o ) data, demonstrates that the Baisakhi–Bhadesar Formation is characterized by type II, a mixture of type II/III and type III kerogen facies and exhibits good source-rock quality and poor to good generative potential in the basin. The studied samples are marginally mature to mature in nature ( T max , 430–450°C; VR o , 0.52–0.72%). A maturity analysis of the basin suggests that during the Late Jurassic most areas were under the oil window zone, except for the Bhakhari Tibba and Miajlar areas. The transformation ratio overlay for the Kimmeridgian–Tithonian source sequences shows better transformations of the source rock in the area of the Shagarh Sub-basin. Kerogen kinetics of the studied Baisakhi–Bhadesar Formation demonstrate that the activation energy ranges between 46 and 74 kcal mol −1 with the significant distribution of activation energy being 54 kcal mol −1 (42.07%), representing a strong heterogeneous type of organic matter in the sediments. Based on lithological, palaeontological and electrolog studies, a shallow-marine to nearshore environment of deposition with a sediment-input direction from the SE has been inferred for the Kimmeridgian–Tithonian sequences. The results of this study quantitatively establish the role of the Kimmeridgian–Tithonian sequence as a source rock, ultimately contributing to the generation of hydrocarbons in the basin along with spatial changes in the quality of source sediments in different parts of the basin.

Depositional environments and thermal maturity of the hydrocarbon source rocks in the Devonian–Early carboniferous Ora Formation from palynological organic petrographic investigations in northern and western Iraq

The study investigates the palynofacies, organic matter character, and hydrocarbon generation potential of this rock unit, based on surface and subsurface samples from the Ora Formation type-section in extreme northern Iraq and the Akkas-3 well in western Iraq, respectively. Dark, mostly oxidized, gelified platy amorphous organic matter (AOM) dominates the palynological components in the surface section, in addition to a few rounded spores and structured phytoclasts. In contrast, palynomorphs, including Ambitisporites avitus, Aneurospora spp., Vallatisporites verrucosus, Acinosporites spp., Verrucosisporites nitidus and the algae Botryococcus, are predominant in studied samples from the Akkas-3 well. Statistical cluster analysis identified three palynofacies types in the surface section based on stratigraphic variations in the particulate organic matter. These vary from high amorphous organic matter (AOM), moderate phytoclast, and low palynomorph abundances that represent proximal suboxic–anoxic shelfal environments to moderate to good AOM and low to moderate palynomorph abundances that represent distal suboxic–anoxic or distal dysoxic–anoxic shelfal environments. The organic petrographic study of the outcrop section also revealed the strong effect of oxidation, where dispersed terrigenous and amorphous organic materials in the form of granular and gelified forms dominate and reflect a terrestrial origin of these components. In the subsurface section, a mixed terrestrial and less marine or lacustrine origin characterized the studied organic matter, where land plant spores (sporinite), in addition to vitrinite and inertinite, are dominant with a few scattered liptinite macerals. The difference in thermal maturity between the outcrop and subsurface samples is likely due to the higher tectonic burial of the outcrop samples that form part of the Northern Thrust Zone of Iraq. Nevertheless, higher abundances of AOM (oil-prone kerogen type II) accumulated in the northern outcrop type section. This might imply that the Ora Formation has a higher potential for hydrocarbon production north of the Akkas field.

A study on the accumulation model of the Santos basin in Brazil utilizing the source–reservoir dynamic evaluation method

The exploration potential within deep-water petroliferous basins holds great promise for oil and gas resources. However, the dearth of geochemical and isotopic data poses a formidable challenge in comprehending the intricate hydrocarbon charging processes, thereby impeding the comprehensive understanding of hydrocarbon accumulation mechanisms and models. Consequently, the establishment of robust source–reservoir relationships in deep-water petroliferous basins represents a pivotal challenge that significantly influences the exploration strategies and the comprehension of hydrocarbon enrichment dynamics within such basins. In this study, we introduce a novel approach, termed the “source–reservoir dynamic evaluation method,” tailored to investigate reservoir accumulation models in deep-water petroliferous basins. This method uses basin simulation technology to recover the thermal evolution history and hydrocarbon generation and expulsion history of source rocks, and on this basis delimits the hydrocarbon kitchen range. At the same time, the maturity of source rocks corresponding to crude oil and natural gas in typical reservoirs is calculated. Then, when the thermal evolution degree of source rocks adjacent to the reservoir reaches this maturity, the corresponding geological period is the main charging period of hydrocarbon. As a typical deep-water petroliferous basin, the Santos Basin in Brazil has abundant oil and gas reservoirs under the thick salt rock, but there are still some fundamental problems such as unclear oil–gas accumulation process and model. Therefore, in this paper, the main charging periods of typical hydrocarbon reservoirs are determined based on the internal relationship between the thermal evolution history of the main source rocks and the maturity of crude oil and natural gas, and then the hydrocarbon accumulation process is analyzed and the dynamic accumulation model is established. Finally, the favorable prospecting direction is pointed out. The results show that the oil and gas in the Barra Velha Formation in the Santos basin are mainly derived from the Itapema Formation lacustrine shale source rock, and the source rock is mainly developed in the Eastern Sag of the Central Depression, and its main hydrocarbon generation period is from the deposition period of Florianopolis Formation to the deposition period of Santos Formation. The main hydrocarbon expulsion period was from the deposition period of the Santos Formation to the Early deposition of the Iguape Formation. The oil and gas in the Barra Velha Formation were mainly charged from the Late deposition period of the Santos Formation to the Early deposition period of the Iguape Formation. During this period, the hydrocarbon migrated vertically along the normal fault formed in the rift period to the trap of the adjacent inheritance structural highs and accumulated in the reservoir, which was dominated by the accumulation model of the “lower generation-upper reservoir-salt cap”. Since the Barra Velha Formation has the characteristics of near-source accumulation, based on the hydrocarbon expulsion center and hydrocarbon expulsion intensity of the source rock of the Itapema Formation, the distribution ranges of 85% and 50% Pre-salt accumulation probability in the Santos basin were calculated by using the quantitative analysis model of the hydrocarbon distribution threshold. It is suggested that the next oil and gas exploration should be carried out in the paleo-structural highs and slope of Class I favorable area (the hydrocarbon accumulation probability is more than 85%) and Class II favorable area (the hydrocarbon accumulation probability is 85–50%).

Influence of igneous intrusions on maturation of the Cretaceous-Eocene source rocks of the offshore Tanzanian Basin

Influence of igneous intrusions on maturation of the Cretaceous-Eocene source rocks of the offshore Tanzanian Basin

CONTRIBUTION OF SEISMIC AND GEOTHERMAL DATA ANALYSIS TO THE ASSESSMENT OF THE HYDROCARBON POTENTIAL OF THE CENTRAL BASIN OF THE D.R. CONGO

This paper presents an evaluation of the hydrocarbon potential of the Cuvette Centrale basin in the Democratic Republic of Congo (DRC) using an integrated approach that combines seismic and geothermal data. The envelope attribute of seismic data was used to identify different rocks of the petroleum system, including potential gas-prone zones. The interpretation of seismic profiles helped to delineate geological units and determine their lithology. Isobath maps based on seismic data revealed the presence of grabens and anticlines, which are favorable geological structures for hydrocarbon accumulation. Analysis of the geothermal gradient and temperature evolution in the formations allowed us to establish source rock maturity maps, highlighting two distinct zones: an overmature zone favorable for gas and a mature zone favorable for oil. These results suggest a strong hydrocarbon potential in the Cuvette Centrale basin.

Control of Earth system evolution on the formation and enrichment of marine ultra-deep petroleum in China

Taking the Paleozoic of the Sichuan and Tarim basins in China as example, the controlling effects of the Earth system evolution and multi-spherical interactions on the formation and enrichment of marine ultra-deep petroleum in China have been elaborated. By discussing the development of “source-reservoir-seal” controlled by the breakup and assembly of supercontinents and regional tectonic movements, and the mechanisms of petroleum generation and accumulation controlled by temperature-pressure system and fault conduit system, Both the South China and Tarim blocks passed through the intertropical convergence zone (ITCZ) of the low-latitude Hadley Cell twice during their drifts, and formed hydrocarbon source rocks with high quality. It is proposed that deep tectonic activities and surface climate evolution jointly controlled the types and stratigraphic positions of ultra-deep hydrocarbon source rocks, reservoirs, and seals in the Sichuan and Tarim basins, forming multiple petroleum systems in the Ediacaran–Cambrian, Cambrian–Ordovician, Cambrian–Permian and Permian–Triassic strata. The matching degree of source-reservoir-seal, the type of organic matter in source rocks, the deep thermal regime of basin, and the burial-uplift process across tectonic periods collectively control the entire process from the generation to the accumulation of oil and gas. Three types of oil and gas enrichment models are formed, including near-source accumulation in platform marginal zones, distant-source accumulation in high-energy beaches through faults, and three-dimensional accumulation in strike-slip fault zones, which ultimately result in the multi-layered natural gas enrichment in ultra-deep layers of the Sichuan Basin and co-enrichment of oil and gas in the ultra-deep layers of the Tarim Basin.

The generation mechanism of deep natural gas in Tabei uplift, Tarim Basin, Northwest China: insights from instantaneous and accumulative effects

The natural gas heavy carbon isotope and high dryness coefficients genesis in Tabei uplift, Tarim Basin has been highly controversial. To investigate the generation mechanisms of natural gas in the Tabei Uplift. Natural gas chemical composition, carbon isotopes were used to analyze the genesis of natural gas, source rock maturity, and basin modeling were conducted to reconstruct the natural gas generation process, and the influences of instantaneous and cumulative effects on natural gas properties was discussed. The results show that the dryness coefficients of natural gas range from 0.62 to 0.99 (average: 0.92), the methane contents range from 30.42% to 96.4% (average: 85.10%), ethane contents from 0.43% to 15.58% (average: 3.39%), propane contents from 0.11% to 11.43% (average: 1.78%), and the methane carbon isotopes range from −47.30‰ to −33.80‰ (average: −36.96‰), ethane carbon isotopes range from −39.60‰ to −33.20‰ (average: −35.57‰), propane carbon isotopes range from −36.90‰ to −28.50‰ (average: −35.49‰). Compared with the actual regional thermal evolution of the source rock (Ro% range from 1.4%∼1.7%), the natural gas exhibits excessively high dryness coefficients and heavy methane carbon isotope characteristics. The natural gas is primary cracking gas and sourced from marine type II kerogen. The dryness coefficient, methane carbon isotopes, and source rock maturity gradually increases from the west to the east. Instantaneous effects and leakage led to the dry gas and relative heavy methane carbon isotopes generated at a low maturity level. The current natural gas in the Ordovician reservoirs was all generated during the Himalayan orogeny. Long period pause of the gas generation between the two hydrocarbon generation phases is the main cause for the instantaneous effects.

Evaluation of thermal maturity of source rock based on geochemical method, a case study of Late Oligocene source rock in Hoa Tra field, Cuu Long basin, Vietnam

The &amp;nbsp;Hoa Tra field is located in the southeast of the Cuu Long basin which has great potential for oil and gas. The source rocks in this area are mainly fine-grained sediments from the late Oligocene and early Miocene, which are located in a continuous deposition zone and under anaerobic conditions. This paper focuses on studying the maturity level of late Oligocene source rock through geochemical analysis methods. Specifically, the paper uses indicators such as T­,&amp;nbsp;R&lt;sub&gt;o&lt;/sub&gt;, MPI-1, T&lt;sub&gt;s&lt;/sub&gt;/(T&lt;sub&gt;s&lt;/sub&gt;+T&lt;sub&gt;m&lt;/sub&gt;) and C&lt;sub&gt;29&amp;nbsp;&lt;/sub&gt;steran 20S/(20S+20R) from Rock-Eval Pyrolysis, Vitrinite reflectance and Gas chromatography-Mass spectrometry methods, respectively, to evaluate the level of thermal maturity of the source rock. The source rocks in the Hoa Tra field mainly contain types I and II, which are poor in vitrinite particles, leading to low&amp;nbsp;R&lt;sub&gt;o&lt;/sub&gt; measurement results. However, when&amp;nbsp;R&lt;sub&gt;o&lt;/sub&gt; is calculated from T&lt;sub&gt;max&amp;nbsp;&lt;/sub&gt;and (MPI-1), it indicates that the thermal maturity of source rock from the upper part of the late Oligocene is in the early mature stage (R&lt;sub&gt;o avg&lt;/sub&gt;= 0.56%), while those from the lower part of late Oligocene are mature and in the phase of oil generation (R&lt;sub&gt;o avg&lt;/sub&gt;= 0.65%). These results are similar to those obtained from assessing thermal maturity using T&lt;sub&gt;s&lt;/sub&gt;/(T&lt;sub&gt;s&lt;/sub&gt;+T&lt;sub&gt;m&lt;/sub&gt; and&amp;nbsp;C&lt;sub&gt;29&amp;nbsp;&lt;/sub&gt;20S/(20S+20R) indicator (the average values for the respective parameters are 0.32 and 0.31 for the upper part, while those are 0.39 and 0.42 for the lower part of late Oligocene). The article also shows that the contribution to the &amp;nbsp;Hoa Tra field is not only from in-situ generated oil but also from migratory oil coming from nearby troughs.

OIL FAMILIES AND GEOCHEMICAL COMPOSITION OF DEVONIAN OILS AT THE RECHITSA FIELD, PRIPYAT BASIN, BELARUS

The sedimentary column at the Rechitsa oilfield in the Pripyat rift basin, Belarus, is dominated by an Upper Devonian synrift succession. The succession includes uppermost Frasnian and mid‐Famennian salt units which are about 1000 m and 2000 m thick respectively. Reservoir rocks consist of sandstones and carbonates in the intra‐, inter‐ and sub‐salt successions. In this paper, the geochemical analysis of 15 oil samples from different stratigraphic intervals at the Rechitsa field is used as a basis for reservoir characterisation. Geochemical studies included biomarker and stable C, N and S isotope analyses.Four genetic oil groups were identified and are referred to as Groups A to D. Oils in Group A came from upper intra‐ and inter‐salt reservoir rocks; the oils are early mature, enriched in heavy (C36+) hydrocarbons, heteroatoms, aryl‐isoprenoids and gammacerane, with low Pr/Ph = 0.6 and a sulphur isotope composition averaging 22.7‰ CDT. Oils in Group B were from sub‐salt reservoirs and are at peak maturity with Pr/Ph = 1, an increased proportion of C27 regular steranes, and a sulphur isotope composition of 8.1‰ CDT. The single oil sample in Group C was from a Proterozoic reservoir. The oil was overmature with a low content of heavy fractions, heteroatoms and steranes; its hopanes composition indicated that it was generated by the same source rock as the oils in Group B. Oils in Group D came from inter‐salt reservoir rocks and were composed of a mixture of Groups A and B oils in roughly equal proportions, as indicated by their average isotope, molecular and biomarker compositions.Observed differences in oil composition were explained in terms of contributions from at least two different source rocks together with variations in source rock maturity. Group A oils were interpreted to have been generated by Famennian carbonate‐rich source rocks containing dominantly marine and bacterial organic matter deposited in an anoxic evaporitic setting. Source rocks for Groups B and C oils were suggested to be composed of OM‐rich marine shales of Frasnian age or older.The geochemical characteristics of the Devonian oils from Rechitsa field, and the oil‐oil and oil‐ source rock correlations reported, will contribute to a better understanding of the petroleum system in the Pripyat Basin although direct oil‐ source rock correlations are not yet available. The presence of at least two source rocks for the Rechitsa oils has been suggested, respectively comprising carbonates in the inter‐salt succession and marine shales and/or carbonates in the sub‐salt succession. The main controls on oil composition in the Devonian reservoir units were the varying contributions from the different source rocks and differences in source rock thermal maturity associated with variations in burial depth and tectonics, together with the stratigraphic distribution of reservoir units which was in turn controlled by the presence of the thick Frasnian and Famennian salt units.

Petroleum system analysis of the komombo basin, southern Egypt: Insights from basin modeling and hydrocarbon geochemistry

Komombo Basin is the only hydrocarbon-producing basin in southern Egypt. However, its petroleum system is still poorly understood, leaving numerous geological questions unanswered. This study integrates seismic, borehole, and geochemical data, coupled with 1D and 2D basin models, to evaluate the hydrocarbon potential and analyze the petroleum system within the Komombo Basin. Geochemical data reveal four main source rocks: the B member of Six Hills, upper Maghrabi, Quseir, and Dakhla. The B member is interpreted as a very good source rock, characterized by Kerogen type II to II/III. The upper Maghrabi and Quseir are considered good to very good source rocks with organic matter type III and II/III, respectively. Conversely, the Dakhla Formation is recognized as a source rock of good to excellent quality with a mixed kerogen type of II/III. Temperature models highlight two heat anomalies during the Early and Late Cretaceous, aligning with the identified rift phases in the basin. The present-day thermal maturity model indicates that the B member is the only mature source rock that has entered the main oil window. However, in the deepest part of the basin, it reaches the gas window. Although the hydrocarbon generation from the B member began in the Early Turonian, most of the kerogen transformed into hydrocarbons during the middle Santonian-early Maastrichtian. Three migration scenarios were tested, however, the first scenario with the invasion percolation migration method aligns more with known hydrocarbon accumulations in the basin. The predicted accumulation zones are found within several sand units, including the A member, C member, sandy intervals within D-G members of Six Hills, and Sabaya-Maghrabi reservoirs. These zones are predominantly situated within structural traps. Comparative analysis using gas chromatograms between recovered oils from the reservoirs and an extracted bitumen sample from the B member source rock reveals a strong correlation among them.