Mature Source Rocks Research Articles

Characterization of a structural trap associated with an intrusive complex: the El Trapial oilfield, Neuquén Basin, Argentina

Abstract Volcanic plumbing systems emplaced in sedimentary basins may exert significant mechanical and thermal effects on petroleum systems. The last decade of research has evidenced that igneous intrusions may enhance thermal maturation of organic matter in source rocks and lead to both small- and large-scale structures that can deeply impact fluid migration or trapping. This contribution describes how the emplacement of a whole intrusive complex generated a dome structure of the overburden, which is the main trapping structure of a large producing oilfield. Our case study is the lower Miocene Cerro Bayo de la Sierra Negra (CBSN) intrusive complex, Neuquén Basin, Argentina, associated with the El Trapial oilfield where the main trapping structure is a large domal antiform centred on the CBSN complex. This study integrates the large subsurface dataset produced during the development of the El Trapial oilfield. More than 1200 vertical wells (producers and injectors) have been drilled in the flanks of CBSN complex. In addition, five 3D seismic cubes have been acquired over the years that have been merged and reprocessed into a single volume. Such a dataset allows a detailed characterization of both the structure affecting the Mesozoic strata and the geometry of the intrusive complex. Igneous rocks have been recognized along the entire stratigraphic section. Sill intrusions appear to concentrate in the shale units and the stacking of them has a direct impact on the doming structure generation. Our study allowed us to establish a direct correlation between the distribution of the intrusions and the extent, amplitude and style of doming, showing that the dome structure results from the emplacement of the intrusive complex. We also show that part of the doming is related to intrusions emplaced in the Mesozoic formations of the Neuquén Basin, whereas the other part of the doming is related to deeper structures not imaged on the geophysical data. We estimate that the amplitude of the doming reaches up to c. 500 m. The voluminous subsurface data, combined with exposed outcrops, makes the CBSN complex a world-class case study for showing how the shallow plumbing system of a volcanic complex may control the growth of large-scale trapping structures for various fluids, such as drinkable water, geothermal fluids and hydrocarbons.

Predicting the thermal maturity of source rock from well logs and seismic data in basins with low-degree exploration

Vitrinite reflectance (Ro) is a significant geological index that evaluates the thermal maturity of source rock. However, measured Ro data and suitable evaluation methods are lacking, making it difficult to predict the thermal maturity of source rock in basin, especially in those with a low exploration degree. In this study, we propose a novel method for estimating Ro from well logs and seismic data using seismic velocity inversion and the vitrinite reflectance-mudstone porosity (Ro-ϕ) model. First, using a wavelet neural network, acoustic transit time curve was reconstructed from spontaneous potential, gamma rays, resistivity, and density logs, and new curve was used as inputs in a colored inversion to obtain seismic relative velocity. Second, a low-frequency model was established to counteract critical frequency and sequence framework constraints. Third, the seismic absolute velocity was merged by relative and low-frequency velocity components. Finally, Ro distributions were calculated using the Ro-ϕ model. Our findings indicate that the inversion effect improved with low-frequency supplement; compared with the graphic and geochemical method, the Ro-ϕ model predicted Ro in poor-data areas more accurately, with a relative error of <9.5205%. We also propose an explanation for the appearance of highly mature source rocks distributed from dispersion to aggregation in depression-rift transitions: the thick stratum in the downthrow wall of boundary faults promote source rock maturity in the rift period; hence, in an open depression, the source rocks in large subsidence areas are highly mature, particularly near the downthrow wall of a boundary fault, which has the highest maturity owing to the superimposed subsidence of the overlying rifted basin.

The impact of igneous intrusions on sedimentary host rocks: insights from field outcrop and subsurface data

Pervasive igneous intrusive complexes have been identified in many sedimentary basins which are prospective for petroleum exploration and production. Seismic reflection and well data from these basins has characterized many of these igneous intrusions as forming networks of interconnected sills and dykes, and typically cross-cutting sedimentary host rocks. Intrusions have also been identified in close proximity to many oil &amp; gas fields and exploration targets (e.g. Laggan-Tormore fields, Faroe Shetland Basin). It is therefore important to understand how igneous intrusions interact with sedimentary host rocks, specifically reservoir and source rock intervals, to determine the geological risk for petroleum exploration and production. The risks for petroleum exploration include low porosity and permeability within reservoirs, and overmaturity of source rocks, which are intruded. Additionally, reservoirs may be compartmentalized by low permeability igneous intrusions, inhibiting lateral and vertical migration of fluids. Based on a range of field studies and subsurface data, we demonstrate that sandstone porosity can be reduced by up to 20% (relative to background porosity) and the thermal maturity of organic rich claystones can be increased. The extent of host rock alteration away from igneous intrusions is highly variable and is commonly accompanied by mechanical compaction and fracturing of the host rock within the initial 10 to 20 cm of altered host rock. Reservoir quality and source rock maturity are key elements of the petroleum system and detrimental alteration of these intervals by igneous intrusions increases geological risk and should therefore be incorporated into any risk assessment of an exploration prospect or field development. Thematic collection: This article is part of the New learning from exploration and development in the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin

The impact of Oligo-Miocene basaltic intrusions on the petroleum system in Gulf of Suez rift basin, Egypt: new insights into thermal maturity and reservoir quality

In recent years, the petroleum industry has prioritized the exploration of new and unconventional petroleum reservoirs. As a result, this study assessed the significance of basaltic intrusions from two key aspects: their impact on the thermal maturity of pre-rift source rocks and their potentiality as reservoirs. The present study attempts to integrate surface field investigations of basaltic dykes in Wadi Nukhul and Wadi Matulla as surface analogs with petroleum system modeling of pre-rift source rocks containing subsurface basaltic intrusions in the Abu Rudeis-Sidri field. Therefore, the fracture networks were observed in Wadi Nukhul and Wadi Matulla, suggesting that both the basaltic dykes and host rocks have interconnected fractures, which is critical for a high-quality reservoir of the dykes and efficient oil expulsion. As a result, the analysis of burial history, temperature, maturity, generation, transformation ratio, and expelled oil quantity revealed a significantly high value for basaltic intrusions. Moreover, the Abu Rudeis-Sidri field had a good petroleum system with thermally mature source rocks by basaltic intrusions. Furthermore, the fractured basaltic intrusions presented a high-quality oil reservoir well-sealed by the thick Rudeis Formation. Oil production has doubled since the discovery of this reservoir. This study introduces a novel approach to understanding the distribution pattern of basaltic intrusions in subsurface and surface analogs, which can serve as a model for exploring new potential unconventional basaltic reservoirs in the Gulf of Suez rift basin.

Geochemical Characteristics of the Mallawa Formation, and its Relationship with the History of Source Rock Formation in the South Makassar Basin, South Sulawesi

A hydrocarbon system to determine the hydrocarbon potential in an area can be determined by the presence of three main components that ensure its existence together, one of main components are source rock. The South Makassar Basin has the potential to have a petroleum system that acts as a source rock for the Mallawa Formation. Source rock is a component of the petroleum system that has the ability to produce and store hydrocarbons, where this rock is generally a rock with fine grains such as coal or shale. Oil and gas exploration in Indonesia is a common thing because there are many prospect areas that have the potential to produce hydrocarbons. The South Makassar Basin is a Tertiary sedimentary basin of land type which is geographically located along West Sulawesi to South Sulawesi and this basin occurs due to tectonics or structures with high frequency. The South Makassar Basin was formed as a result of the expansion of the Makassar Strait which occurred at no younger than the Early Paleocene age where the tectonic consequences would influence the maturation process of the source rocks in the South Makassar Basin. Apart from that, in this research a geochemical method was carried out in the form of laboratory analysis to determine the maturity of the source rock using cuttings samples. So this research provides something new in the exploration of the maturity of source rocks, which in the South Sulawesi area has a complex tectonic setting.

A tectono-thermal perspective on the petroleum generation, accumulation and preservation in the southern Ordos Basin, North China

The southern Ordos Basin has excellent petroleum exploration prospects. However, the tectono-thermal history and the controls on petroleum generation, accumulation and preservation conditions in southern basin are unclear. In this study, we analyzed the present geothermal field, paleo-geothermal gradient, maturity of the hydrocarbon source rocks, uplift and cooling process and tectono-thermal evolution history. In the study area, for the Ordovician, Permain and the Triassic strata, the present temperature is low (30−70 °C) in the southeastern area but high (80−140 °C) in the northwestern area. The paleo-geothermal gradient varied from 24 °C/km to 30 °C/km with a heat flow of 58–69 mW/m2 (i.e., a medium-temperature basin). The paleo-temperatures are higher than the present temperatures and the maximum paleo-temperatures controlled the thermal maturity of the source rocks. The vitrinite reflectance (Ro) values of the Triassic strata are >0.7% and the thermal maturity reached the middle-mature oil generation stage. The Ro values of the Permian-Ordovician strata are >1.8% and the thermal maturity reached the over-mature gas generation stage. The southern Ordos Basin has experienced the multiple tectonic events at the Late Ordovician Caledonian (452 Ma), Late Triassic (215 Ma), Late Jurassic (165−160 Ma), End-Early Cretaceous (110−100 Ma) and Cenozoic (since 40 Ma). A large-scale tectono-thermal event occurred at the End-Early Cretaceous (110−100 Ma), which was controlled by lithospheric extension, destruction and thinning. This event led to the highest paleo-temperatures and thermal maturities and coeval with the peak period of petroleum generation and accumulation. The southern Ordos Basin has undergone rapid and large-scale uplift since the Late Cretaceous due to expansion of the northeastern margin of the Tibetan Plateau, uplift of the Qinling orogenic belt and thrust faulting in the Liupanshan tectonic belt. The southern Ordos Basin experienced tectonic overprinting that was strong in the south and weak in the north. The strongest overprinting occurred in the southwestern part of the basin. The large-scale uplift, denudation and faulting led to oil and gas loss from reservoirs. The petroleum generation, accumulation and preservation in the southern Ordos Basin were affected by deep lithospheric structures and the tectono-thermal evolution. This work provides a novel tectono-thermal perspective on the petroleum generation, accumulation and preservation condition of the southern Ordos Basin.

Source rock characterization and biomarkers analysis of Adar and Galhak Formations, Rawat central sub-basin, White Nile basin, Sudan

Geochemical analysis was conducted on shaly-cutting samples from various formations in Rawat Central Sub-Basin using Rock-Eval pyrolysis, vitrinite reflectance, and GC-MS to determine the characteristics of different source rocks in the basin, including their hydrocarbon potential, maturity, and organic facies. It can be inferred that most samples exhibit characteristics of gas-prone source rocks. Only Adar and the shaly upper section of the Campanian Galhak formation are promising in having excellent source rocks with TOC reaching up to 12%, HI (563–919 mg/g TOC) Tmax (443–445 °C), and S2 (77 mgCO2/g rock) with a potential to generate oil. The maturity data of both Tmax and vitrinite reflectance revealed that these source rocks are within the early mature to early peak mature with dominant kerogen type of a mixed type II-III kerogen. Few samples reflect a pure type I and type II kerogen.The biomarkers data revealed that three possible organic faces can be identified. Slightly brackish anoxic to sub-anoxic deep lacustrine/marine shale to marginal marine shale (coastal plain estuary) characterized by (Pr/Ph < 1, High Hopanes, C23 TT, Pr/Ph < 1, C25TT/C26TT and C24TeT/C26TT < 1, C27 ∼ C29 sterane, high Gammacerene and β-carotane) (Organofacies I). Mixed facies of distal lacustrine to coastal plain proximal lacustrine (Organofacies II) characterized by (High waxiness, Pr/Ph > 2, C25TT/C26TT and C24TeT/C26TT > 1, high C28 sterane). Sub-oxic terrestrial to coastal plain estuary/bay facies characterized by (Pr/ph ∼1, C25TT/C26TT and C24TeT/C26TT > 1, low Gammacerane, High C29 sterane) (Organofacies III). Lower Galhak formation was deposited in slightly brackish, clay-rich, deep lacustrine to mixed marginal marine shale estuary representing Organofacies I with an average terrestrial input forming type II & III kerogen. For Galhak formation, the depositional environment ranged from proximal sub-oxic sallow lacustrine to distal sub-oxic lacustrine (Organofacies II) with a high terrestrial input in the Lates. Adar formation was deposited in a clay-rich, sub-oxic, terrestrial (Fluvial) to coastal plain (estuary/bay) (Organofacies III) with an average terrestrial input generating a mixed type II/III kerogen. The relatively low 20S/(20S + 20R) and ββ/(ββ + αα) C29 suggest an early maturation in Adar formation and early to peck mature source rocks in Galhak formation.

Helium - Relationships to other reservoir gases and some implications for exploration: The New Mexico Example

Helium (He) is the second most abundant element in the universe after hydrogen but is relatively rare on earth. He occurs as two stable isotopes, 3He and 4He. 4He is the dominant isotope in crustal gases and is a radiogenic decay product of uranium and thorium mainly in granitic basement rocks. 3He is dominantly primordial and primarily originates from the earth’s mantle. 3He may also be formed by radiogenic decay of 6Li (Lithium) which may be found in argillaceous sediments deposited in evaporitic settings. Although He occurs in most natural gases, it almost always occurs in extremely low, subeconomic concentrations, less than 0.1%. It is rare in concentrations more than 1%. A very few small reservoirs have gases with more than 7% He. Other gases that constitute the dominant components of helium-bearing natural gases are nitrogen (N2), carbon dioxide (CO2), and methane (CH4). The highest He concentrations occur where the dominant gas is N2 but most He has historically been produced as a byproduct of gases that are hydrocarbons. Hydrocarbons are generated from petroleum source rocks. Their presence in a reservoir is dependent upon the presence of a mature source rock in the basin and a migration path between the source rock and the reservoir. Large accumulations of CO2 in the southwestern U.S. resulted from the degassing of rising Tertiary magmas and subsequent migration of the gases into crustal reservoirs. N2 appears to originate mostly from degassing of the mantle but may also be formed in some strata by the thermal maturation of kerogens or by diagenetic alteration of clays or organic compounds in red bed sequences. The presence of economic concentrations of He in reservoir gases is dependent not only on an adequate source of 4He generated from granitic basement rocks but also on accommodating flux rates of N2, CO2, and CH4. These gases differ in their origins, places of generation and rates of generation, migration and emplacement. While basement-derived 4He and N2 enter reservoirs at slow rates over long periods of geologic time, hydrocarbons and CO2 enter the reservoir over much shorter time periods and dilute the 4He and N2. Basement-derived gases may be characterized by differing N2:He ratios which may indicate greater rates of He production within the crust in some areas. Exploratory drilling for He on Chupadera Mesa in the late 1990’s and early 2000’s encountered He-rich gases in Lower Permian strata. Isotopic analyses suggest that 93% of Chupadera Mesa He originated from radiogenic decay in crustal rocks while 7% is derived from the mantle or with a possible contribution by evaporitic Permian shales. Marked differences in the CO2 concentrations in different strata indicate that some strata acted as carrier beds for magmatically-derived CO2 while strata with N2-rich and CO2-poor gases were isolated from CO2 sources.

A novel approach for evaluating the transport capacity of sandstone carriers and determining effective hydrocarbon migration channels: Application to the Pinghu Slope Belt of the Xihu Depression, East China Sea Basin

Preferential hydrocarbon migration pathways are of great significance to reveal and predict large-scale hydrocarbon accumulation. However, hydrocarbon migration within heterogeneous sandstone carriers is highly complex and involves geological and technical uncertainties. In this study, the hydrocarbon flow coefficient (Chf) considering the sandstone heterogeneity and fluid properties was first defined to quantify the seepage performance of sandstone carriers using experimental, geological and geophysical techniques. Through two-dimensional numerical simulation, the hydrocarbon convergence coefficient (Chc) was proposed to characterize the differential hydrocarbon convergence controlled by structural morphology. These two parameters were then integrated into the hydrocarbon transport coefficient (Cht) to comprehensively evaluate the hydrocarbon transport capacity of sandstone carrier, and finally combined with the charging conditions to determine the effective migration channels. The Pinghu Formation in the Pinghu slope belt of Xihu Depression, East China Sea Basin, characterized by large-scale lateral migration of hydrocarbons, is selected as a case study. The results demonstrate that only sandstone carriers with Cht values greater than 10 cm2/s and extensive contact with mature source rocks can serve as effective migration channels. In the effective channels with insufficient hydrocarbon supply, the migration intensity decreases rapidly and only small-scale hydrocarbon migration occurs, while the effective channels with sufficient hydrocarbon supply are accompanied by large-scale hydrocarbon occurrence and the migration intensity weakens slowly. Consequently, three effective channels conducive to hydrocarbon migration were determined in the sandstone carrier units of Pinghu Formation. The quantitative method in this study can be used to predict preferential hydrocarbon migration pathways and reduce exploration risks.

Assessing the impact of thermal maturation on the evolution of organic chemistry of Bakken Shale: Insights into oil generation

Early development of the Bakken Petroleum System recognized the significance of source rock maturation and the onset of oil generation in determining the geographic limits of production. The process of oil generation kinetics within source rocks involves intricate chemical reactions, where the nature of organic matter and thermal history influence the production of petroleum products. While simple models work well for some kerogen types (Type I), they fail for others (Type II and III), revealing the limitations of assuming invariant kinetic properties. This study explores the complexity of oil generation kinetics and its significance, particularly in the context of the Bakken Formation. Various methods have been used to identify the boundaries of oil sources, yet many are inductive. This research introduces a novel method to distinguish between catagenesis and diagenesis in Bakken's organic matter.A common linear relationship between activation energy (Ea) and frequency factor (ln(A)) appears in kinetic studies of source rocks, often attributed to statistical errors. This study investigates these relationships, revealing non-statistical compensation effects. Furthermore, extended kinetic models uncover a range of behaviors, highlighting the complexity of oil generation pathways. Notably, a kinetic compensation effect (KCE) is observed in the Bakken Formation, closely resembling findings for Type II kerogen. These compensation effects are not statistically forced, emphasizing their physiochemical origins. This research sheds light on the diverse KCEs within the Bakken Formation through a combination of experimental maturation, core analyses, and kinetic modeling. The study suggests that provenance, particularly for Type II kerogen, plays a crucial role in these effects. The data reveal multiple KCE patterns, including linear, inclined arch, and random clusters, with some transitioning between patterns during the oil generation process. These findings underscore the complexity of oil generation kinetics and its dependency on organic provenance. They also provide valuable insights for understanding oil reservoirs in the Bakken Formation and beyond.

Geometric characterization of subsurface igneous bodies and their impact on source-rock maturation in the Shushan Basin, northern Western Desert, Egypt

Geometric characterization of subsurface igneous bodies and their impact on source-rock maturation in the Shushan Basin, northern Western Desert, Egypt

Utility of fluid inclusion paleo-temperature in petroleum system modelling: A case study from western offshore, India

The paleo-temperature (Th) data from fluid inclusions are utilized for thermal history modelling using PetroMod software. Generally, bottom hole temperature (BHT) and vitrinite reflectance (Ro) measurements are widely used in petroleum system modelling (PSM) in the oil industry for calibration purposes. Th representing the minimum temperature of fluid entrapment estimated from fluid-inclusion study provides extra support to build the thermal models for PSM. Fluid inclusion parameters along with Rock-Eval pyrolysis analysis have been used to predict the maturity of oil in terms of API gravity as well as the maturity of source rocks respectively. Two exploratory wells RV-1 (Mumbai Offshore Basin) and KK4C-A-1 (Kerala-Konkan Offshore Basin), India were examined and the Th from most of the fluid inclusions of wells RV-1 and KK4C-A-1 fell in the oil window range of 60–140 °C suggesting thermal conditions favourable for oil generation in both of the wells. Th of coeval aqueous inclusions along with the Hydrocarbon Fluid inclusions (HCFIs) was used to calibrate PSM. Vital parameters show that source rocks of well RV-1 are mature and that of well KK4C-A-1 are immature. Two sets of PSM are created in terms of generation and expulsion for the dry wells RV-1 and KK4C-A-1 and calibrated each well using fluid inclusion Th and BHT. From the fluid inclusion analysis method, it is evident that hydrocarbon generation happened in both wells and the paleo-temperature indicates that the formations of both wells were subjected to temperatures in the oil window range, even though it was designated as dry wells in the present scenario. The present study highlights the application of fluid inclusion paleo-temperature (Th) during calibration instead of commonly used methods. We could obtain desirable and accurate data output from PSM using Th calibration.

Formation of volatile organic sulfur compounds by low thermal maturation of source rocks: A geochemical proxy for natural gas

Volatile organic sulfur compounds (VOSC) are trace components of natural gas that can provide substantial information regarding gas origins, migration, and key processes such as H2S generation and its occurrence in natural gas reservoirs. In the current study we demonstrate the applicability of VOSC as a proxy for gas-source rock correlations and identification of interactions between H2S and other natural gas components. We studied the molecular and isotopic compositions of VOSC formed during low-level thermal maturation (%Ro equivalent = 0.60–0.71) of six different immature source rocks covering a variety of kerogens (types I, II, II-S and III). Anhydrous pyrolysis experiments (300 °C, 72h) were performed on all the source rocks studied, and the produced gases were analyzed for their molecular compositions and compound specific sulfur isotopes of the various VOSC formed. The formed gases were either dominated by CH4 (32.2–49.9%) or CO2 (31.9–46.2%) and contained a variety of alkanes in the C2–C5 range. H2S formed in 6 out of 8 experiments at concentrations ranging from 0.6 to 4.3%. The results demonstrated formation of VOSC in all experiments, regardless of kerogen types or source rock lithologies. The formation of thiols (16–121.2 ppm) in the produced gas was restricted to those experiments that contained H2S. This indicates that thiols formation is limited to gas-phase interactions between H2S and hydrocarbons. In contrast, thiophenes formed in all experiments (14.9–1778.8 ppm) regardless of H2S presence. Thiols preserved the δ34S signal of their associated H2S due to gas-phase interactions between the two, while thiophenes showed no interaction with the associated H2S and instead preserved the δ34S signature of the bulk kerogen (within 3.5‰ on average) of each source rock. This work demonstrates the applicability of thiophenes to act as a gas-source rock proxy for natural gas and thiols as a proxy for identification of present or paleo-interactions between natural gas and H2S.

Deep learning integrated approach for hydrocarbon source rock evaluation and geochemical indicators prediction in the Jurassic - Paleogene of the Mandawa basin, SE Tanzania

The world's energy demands are growing at an unprecedented rate, and the exploration of new hydrocarbon sources is more important than ever. Therefore, the objective of this study was first to quantitatively analyze hydrocarbon source rock potentiality of the Triassic-Jurassic of Mandawa Basin based on the generalized group method of data handling neural network (g-GMDH), Machine learning, and Geochemical using well logs data. Then a novel g-GMDH was presented to predict a continuous geochemical log profile of TOC, Tmax, S1, and S2. It was observed that the basin's hydrocarbon source rocks are classified as fair to very good source rocks with TOC contents ranging from 0.5 to 8.7 wt%. The source rocks contain mixed kerogen type II and III, which are oil and gas-prone, ranging from immature to mature source rocks. The results of the predictive models indicated that the g-GMDH model trained better whilst generalizing well throughout the testing data than both GPR and SVM models. Specifically, the g-GMDH when tested on unseen data had the least value of MSE = 0.18, 2.35, 0.08, and 61.74 for TOC, Tmax, S1, and S2 respectively, and MAE = 0.45, 1.37, 0.17 and 11.55 for TOC, Tmax, S1 and S2 respectively. The g-GMDH model was further applied to assess the source rock and predict the geochemical information in the East Lika well, which lacks core data. The proposed model can offer rapid and real-time values of geochemical indicators and are independent of laboratory-dependent parameters therefore, can be adopted as an improved technique for evaluating source rocks in frontier basins.

Determination and petroleum geochemical significance of short-chain alkylbenzenes in lacustrine source rocks

The determination of short-chain alkylbenzenes (C0-4) in source rocks has always been a challenge due to potential losses during pretreatment processes such as solvent extraction of the soluble organic matter. This work proposes a method for analyzing short-chain alkylbenzenes in solid powder samples from source rocks by combining headspace (HS)-solid phase microextraction (SPME)-Arrow and gas chromatography-mass spectrometry (GC–MS). The recommended optimal conditions of HS-SPME-Arrow are: use of a polydimethylsiloxane (PDMS) phase with a 250 μm thickness coated fibre, an extraction temperature of 90 °C, exposure time of 13 min, and desorption time of 8 min. The biomarkers and short-chain alkylbenzenes of 37 lacustrine source rocks with varying degrees of thermal maturation from different sedimentary basins in China were analyzed using this method. Three parameters based on short-chain alkylbenzenes isomers were then proposed, including the dimethyl-4-ethylbenzene ratio (DM4EBR), the 1,2-dimethylethylbenzene ratio (1,2-DMEBR), and the trimethylbenzene ratio (TMBR), which showed significant linear correlation with vitrinite reflectance of the source rocks. These can be used to evaluate the maturity or hydrocarbon generation stage of such source rocks, ranging from immature-low mature to postmature stages. An additional three parameters, including the dimethylethylbenzene ratios (DMEBR-1 and DMEBR-2) and the 1-methylisopropylbenzene ratio (1-MiPBR), were also proposed; these related to the organic matter inputs and depositional environments of the source rocks and can be used to identify the organic matter input and depositional environment conditions of source rock samples prior to the late stage of oil generation (Ro < 1.2 %). The usefulness of short-chain alkylbenzene parameters in indicating organic matter inputs, depositional environment conditions, and thermal maturity levels makes them valuable tools for geochemical studies of highly matured light oils and condensates.

Characteristics of Hydrocarbon-Generating Pressurization in Shale Series of Fengcheng Formation in the West and South of Mahu Sag, the Junggar Basin, China

Formation overpressure is an important controlling factor for the formation of high-yield oil reservoirs in the shale series of the Permian Fengcheng Formation in the west and south of Mahu Sag, the Junggar Basin. Hydrocarbon-generating pressurization (HGP) is an important cause of overpressure in the shale series of Fengcheng Formation, but the evidence for this viewpoint is insufficient. There is still no systematic study on the quantitative calculation and distribution characteristics of HGP in the Fengcheng Formation shale series. The control effect of HGP on the formation of high-pressure and high-yield reservoirs is still unclear. Therefore, by using the data of mudstone logging and measured formation pressure, the causes of overpressure in the Fengcheng Formation shale series are clarified. The predicted organic matter abundance, the predicted maturity and thickness of source rocks, and the statistical ratios of mudstone thickness to formation thickness in each section of Fengcheng Formation are used for HGP of shale series. Combined with the physical characteristics of reservoir rocks and the geochemical characteristics of oil, the control effect of HGP on the formation of high-pressure and high-yield reservoirs is analyzed. The results indicate the following: (1) The organic matter abundance and the thickness of source rocks predicted by the logging data gradually decrease from the eastern lake basin area to the western slope area. (2) The HGP of shale series in Fengcheng Formation is related to the hydrocarbon generation capacity and the overpressure preservation conditions of the source rocks. The HGP can be quantitatively predicted by comprehensively using the organic matter abundance, the maturity, the thickness of source rocks, and the ratios of mudstone thickness to formation thickness. (3) The HGP in the Fengcheng Formation shale series also gradually decreases in distribution characteristic from the eastern lake basin area to the western slope area. (4) The oil accumulation mode of the Fengcheng Formation shale series is that, with the drive of overpressure, the oil migrates slightly within the layer, and finally accumulates to form the oil reservoir. The research results are helpful to understand the distribution characteristics of HGP and the formation mechanism of high-pressure and high-yield reservoirs in the shale series of Fengcheng Formation in the west and south of Mahu Sag, and are of great significance to guide the exploration and development of shale oil and tight oil.

Geochemical Evaluation of the Lower Senonian Ogugu Shale, Southern Benue Trough, Nigeria: Implication for Source Richness, Quality and Petroleum Potential

The Lower Senonian Ogugu Shale is the topmost layer of the Coniancian-Santonian depositional unit in the Southern Benue Trough. Sediments of this unit have been suggested to have huge potential for hydrocarbon generation. However, detailed geochemical studies on the organic matter source, thermal maturity and the hydrocarbon potential Ogugu Shale are still missing. For the present study, a total of 16 cuttings and 3 core samples of the Ogugu Shale from Amasiodo-1 well were subjected to total organic carbon (TOC), Rock-Eval pyrolysis and gas chromatography mass spectrometry (GC-MS) analyses in order to characterize the organic matter richness, kerogen type and liquid hydrocarbon-generative potential in the samples. The TOC values (0.70 to 1.20 wt. %) and Rock-Eval pyrolysis data S2 (0.26-0.73 mg HC/g rock) as well as its calculated parameters Hydrogen Index (HI; 23-72 mg HC/g rock) and Generative Potential (GP; 0.33-0.84 mg HC/g rock) suggest poor to fair organic rich rock containing dominantly terrestrially derived Type III kerogen. The biomarkers as well as the source-indicating aromatic hydrocarbons in the samples suggest contributions from mixed aquatic and vascular organic matter deposited under oxic-dyoxic conditions of deltaic paleoenvironment. The Rock-Eval pyrolysis Tmax (434-4560 C) including the derived vitrinite reflectance (Rc; 0.65-1.05%) indicate thermally matured source rocks. The thermal maturity status of Ogugu Shale is further supported by molecular thermal parameters from the saturate and aromatic compounds. This study therefore conclude that that the Senonian Ogugu Shale of the Southern Benue Trough contain thermally matured fair quantity of organic matter with poor hydrocarbon potential.

Tectonic-thermal history and hydrocarbon potential of the Pearl River Mouth Basin, northern South China Sea: Insights from borehole apatite fission-track thermochronology

The Pearl River Mouth Basin (PRMB) is one of the most petroliferous basins on the northern margin of the South China Sea. Knowledge of the thermal history of the PRMB is significant for understanding its tectonic evolution and for unraveling its poorly studied source-rock maturation history. Our investigations in this study are based on apatite fission-track (AFT) thermochronology analysis of 12 cutting samples from 4 boreholes. Both AFT ages and length data suggested that the PRMB has experienced quite complicated thermal evolution. Thermal history modeling results unraveled four successive events of heating separated by three stages of cooling since the early Middle Eocene. The cooling events occurred approximately in the Late Eocene, early Oligocene, and the Late Miocene, possibly attributed to the Zhuqiong II Event, Nanhai Event, and Dongsha Event, respectively. The erosion amount during the first cooling stage is roughly estimated to be about 455–712 m, with an erosion rate of 0.08–0.12 mm/a. The second erosion-driven cooling is stronger than the first one, with an erosion amount of about 747–814 m and an erosion rate between about 0.13–0.21 mm/a. The erosion amount calculated related to the third cooling event varies from 800 m to 3419 m, which is speculative due to the possible influence of the magmatic activity.

Analysis of the Spatial Distribution Characteristics of Crude Oils with Different Freezing Points and the Genetic Mechanism of High-Freezing-Point Crude Oils in the Dongying Sag.

The freezing point of crude oils is an important factor affecting the process of exploration, development, and transportation of crude oils. In the Dongying Sag, the freezing point of crude oils varies greatly in space, and high-freezing-point crude oils have been found in many structural belts. The freezing point of crude oils in the Dongying Sag is generally high, ranging from -40 to 80 °C. The distribution of high-freezing-point crude oils in the Dongying Sag is scattered, and they have been found at different depths, layers, and structural belts, with relatively more occurrences in specific areas. Based on the relationship between the wax content and the resin + asphaltene content, the high-freezing-point crude oils in the Dongying Sag can be classified into three types (type A, type B, and type C). Type A, type B, and type C high-freezing-point crude oils are mainly found in the gentle slope zone, depression zone, and uplift zone, respectively. The contents of wax and resins + asphaltenes in crude oils are the key factors controlling the freezing point of crude oils in the Dongying Sag. Oil source correlation using biomarkers and n-alkane carbon isotopes demonstrates that different types of high-freezing-point crude oils are generated from different source rocks, indicating that the source of crude oils is not the only factor controlling the freezing point of crude oils. The hydrocarbon-generating parent material of hydrocarbon source rocks developed in different depositional environments of the Dongying Sag is generally characterized by the dominance of bacteria and algae and is supplemented by terrestrial higher plants. This lays the material foundation for the formation of waxes during the maturation of hydrocarbon source rocks. The change of temperature and pressure conditions during the process of oil expulsion from source rocks and migration in the carrier bed will lead to phase fractionation and composition changes of oils, thus forming type A freezing point crude oils in the slope zone and type B freezing point oils in the depression zone. The increase in resin and asphaltene content caused by biodegradation and water washing in shallower buried oil reservoirs is the reason for the formation of type C high-freezing-point crude oils. The research results indicate that the organic matter composition and hydrocarbon alteration during migration and accumulation jointly control the formation of high-freezing-point crude oils in lacustrine basins. The extensive input of terrestrial organic matter into the source rocks of the lacustrine basin laid the foundation for the formation of high-freezing-point crude oils, and the migration fractionation and biodegradation of the crude oils further promoted the formation of high-freezing-point crude oils.

Evaluation of Late Paleozoic Over-High Maturity Source Rocks in the Erlian Basin and Its Adjacent Areas

Evaluation of Late Paleozoic Over-High Maturity Source Rocks in the Erlian Basin and Its Adjacent Areas