Stage Of Hydrocarbon Generation Research Articles

Sedimentary Facies, Palynology, and Organic Geochemistry of Eocene Kalumpang Formation in Lariang and Karama Areas, West Sulawesi, Indonesia

The Kalumpang Formation was deposited in a delta plain setting. A Middle to Late Eocene age (Proxapertites operculatus zone) was inferred from palynological analysis, with a paleoenvironment in a coastal plain setting with a strong terrestrial influence. Samples from the Kalumpang Formation indicate a marginal to early mature stage for hydrocarbon generation. It is mostly composed of gas-prone to oil and gas-prone Type III kerogen facies. The biomarker character of both the rock and oil samples suggests a terrestrial origin, with a significant contribution of estuarine or bay organic material. The oil derives from a non-carbonate lithology, while the rock samples are from carbonate/calcareous shale origin. The abundance of oleanane compound and C30 resins suggests higher plant angiosperm input of Late Cretaceous or younger age for both the rock and the oil samples. The oil seep contains more abundant oleananes compared to the carbonaceous mudstone of the Kalumpang Formation. This suggests that the oil originated from more marine facies than the rock samples, which were deposited in a delta plain setting. This study demonstrated the agreement of depositional environment interpretation and age assessment between lithofacies, palynological, and organic geochemistry analysis.

Thermal maturity evaluation on mildly artificially oxidised sporomorphs: A comprehensive calibration of palynomorph darkness index (PDI) with vitrinite reflectance

The assessment of thermal maturity of organic matter dispersed in sedimentary rocks is a fundamental task in geological studies, including the modelling of burial history of sedimentary basins, palaeotemperature evolution and the hydrocarbon generation assessment. Palynomorph Darkness Index (PDI) is a quantitative method for evaluating thermal maturity, based on the RGB image-analysis of palynomorphs. The growing use of this method has demonstrated the need for calibration against other maturity indicators such as vitrinite reflectance (Avg. VRo), Tmax, SCI (Spore Color Index) and TAI (Thermal Alteration Index). In the present study, PDI was determined on continental palynomorphs and compared with a large dataset of vitrinite reflectance measurements from the same samples, covering a thermal maturity range between the immature and overmature stages of hydrocarbon generation. The selected samples, belonging to twenty-five different wells, were previously oxidised with nitric acid (60%HNO3) for approximately 20 min to facilitate routine palynostratigraphic investigation. Calibration against vitrinite reflectance resulted in two linear correlation equations, one for Avg. VRo below 0.7% and another for values above 0.7%. Additionally, six samples from the Selli level of the Aptian Gorgo a Cerbara section (Umbria-Marche Apennine, Central Italy) were analysed to understand the differences in PDI values between artificially oxidised and unoxidised organic matter. The analysis showed a discrepancy of approximately 19% in PDI values for the same thermal maturity between unoxidised and oxidised sporomorphs. Our results confirm that PDI is a reliable and valid method for evaluating thermal maturity of organic matter, particularly when standard methods cannot be applied. Moreover, comparison with published data concerning other palynomorph groups (i.e., acritarchs) further supports the usefulness of this technique in geological investigations.

Exploitation and Utilization of Generated Oil and Gas by Pyrolysis Simulation Modeling of Shale Source Rocks under the Condition of In Situ Conversion

Previous studies have mainly focused on the source rocks of the 7th Member of Yanchang Formation (Chang 7 Member) in the Ordos Basin, with very few studies focusing on the extracts from the source rocks. These extracts have important guiding significance for studying the in situ conversion process of shale oil. Taking the shale source rock of the Chang 7 Member as an example, this paper selected the extract of shale source rock (i.e., retained oil), which has been less studied previously, as the sample to carry out the hydrocarbon-generating pyrolysis simulation experiment of a semi-open–semi-closed system. Seven groups of parallel simulation experiments were designed with a pressure of 20 MPa. The generated oil and gas were collected and quantified, and their geochemical characteristics were researched. In addition, the generated oil and gas were investigated from aspects of cumulative yield and net increased yield, and the chromatographic and mass spectral characteristics of the generated oil were also researched. Based on this, an inductive hydrocarbon generation model of retained oil in shale source rocks was established: slow hydrocarbon generation stage (300–320 °C), rapid hydrocarbon generation stage (320–360 °C), and residual oil pyrolysis stage (0.79%Ro–1.47%Ro). This study is of important significance to guide the research on the in situ conversion process of shale source rock.

A tale of two vein types: Bed-parallel fibrous versus blocky filled fractures in organic-rich shales and their overpressured hydrocarbon fluids

Bed-parallel fractures are a common feature of organic-rich shales, and are generally interpreted as records of fluid overpressures due to hydrocarbon generation. However, the textural features of such cemented fractures differ widely, and the relationships between these textures and the vein-forming (fracturing and filling) processes—and, critically, their respective roles in accumulation and migration of hydrocarbons—remain uncertain. Here, we compare the physical conditions and opening mode of bed-parallel cemented fractures that show either fibrous texture indicative of antitaxial growth that kept pace with fracture dilation (commonly referred to as “beef”), or blocky texture indicative of unimpeded syntaxial crystallization into an open, fluid-filled space. Specifically, we analyzed formation conditions of bed-parallel fibrous filled fractures in the Shahejie (Eocene) shales, Bohai Bay Basin, east China, and the bed-parallel blocky filled fractures in the Wufeng-Longmaxi (Ordovician-Silurian) shales, Sichuan Basin, southwest China, to evaluate root causes for the different textures of these cements and discuss their roles in self-sourced hydrocarbon accumulation. We report that fluid inclusions in each filling type show distinct and systematic differences in the magnitude of fluid overpressure during different hydrocarbon generation stages of catagenesis. The formation of bed-parallel fibrous filled fractures, including the initial hydraulic fracturing and subsequent crystallization, occurred during the main stage of liquid hydrocarbon generation (i.e., the oil window) when lithostatic fluid pressures were achieved only sporadically and modest overpressures less than lithostatic usually prevailed. The initial bed-parallel fracturing of blocky fillings, in contrast, occurred during the main gas generation stage (i.e., the gas window), and subsequent blocky crystals precipitated after this stage during uplift after the maximum burial. In this case, super-lithostatic overpressures of the CH4-saturated fluids persisted essentially continuously and actively expanded the fractures at rates that were not met by the crystallizing cements.Such a model for blocky crystallization in an open horizontal space supported by super-lithostatic fluid pressures in petroliferous systems in sedimentary basins, is analogous to some systems in metamorphic rocks including even orogenic gold deposits, and some magmatic settings, especially related to S-type granites where they form greisens and tin-tungsten deposits by blocky filling of wolframite and quartz, and I-type granitoids where coarse muscovite veins occur for example in the deep roots of porphyry copper systems, as well as numerous pegmatites. Some elements that each of these settings share with the shale-hosted, bed-parallel blocky filled fractures, include that they involve in situ fluid production (by metamorphic devolatilization or magmatic degassing) and fluid escape is stifled by low background permeability such that fluid overpressures can build up, at least periodically, to match or exceed the lithostatic load. As a result of these divergent bed-parallel fracture filling processes, the fibrous textures record conditions of modest permeability that favored accumulation of nascent liquid oil, whereas the blocky fracture cements represent open fractures that contributed to permeability and expulsion of gas. We conclude that the fibrous filled fractures record an opening mode that was beneficial for shale oil enrichment, whereas dilation of blocky filled fractures provides important conduits for hydrocarbon expulsion and release of shale gas.

Enrichment characteristics and exploration potential of the Permian marine shale gas in the Wujiaping Formation, Sichuan Basin, SW China

Shale gas exploration has achieved global success in marine shales. This study analysed geochemical, mineralogical, porosity, permeability and gas‐bearing parameters of organic‐rich shales in the Permian Wujiaping Formation in the Sichuan Basin. A comprehensive comparison was conducted with the Longtan Formation transitional shales and typical commercially developed marine shales. The results showed that: (1) siliceous shale within the Wujiaping Formation exhibits total organic carbon content ranging from 0.60% to 9.53% (average 4.45%) and vitrinite reflectance (Ro) ranging from 1.83% to 2.14% (average 1.98%), indicating an overmature stage of hydrocarbon generation. Porosity varies from 0.48% to 11.8% (average 4.94%), with an average content of 51.4% brittle minerals (quartz+calcite+dolomite) and calculating gas content exceeding 3 m3/t based on logging data. Effective sealing is achieved by the overlying carbonate of the Changxing Formation and the underlying carbonate of the Maokou Formation. (2) The primary storage space of the siliceous shale in the Wujiaping Formation encompasses diverse organic matter pores, clay mineral pores and microfractures. The porosity and permeability of the Wujiaping Formation marine shale ranges from 0.48% to 11.8% and 0.0053 to 0.8450 mD. Total gas content was estimated between 3 to 12 m3/t averaging 6 m3/t. (3) By comparing Permian Wujiaping Formation shales with Longtan Formation transitional shales, Wufeng Formation‐Longmaxi Formation shales and the typical North American marine gas shales (such as Barnett, Ohio, Antrim, New Albany, etc.), we conclude that marine siliceous shales within the Wujiaping Formation exhibit enrichment conditions comparable to established marine shales and superior to Permian transitional shales. The favourable upper and lower seals of the Wujiaping Formation resemble those of the Barnett shale gas reservoirs. In conclusion, the marine shale in Wujiaping Formation holds potential for substantial shale gas reservoirs and is poised for strategic exploration and development breakthroughs in the northeast and east Sichuan Basin.

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.

Constraining multi-stage and protracted oil generation of alkaline lacustrine source rocks by heteroatomic compounds

It is unclear whether source rocks deposited in ancient alkaline lakes undergo multiple stages of hydrocarbon generation, particularly of oils. In this study, the lower Permian Fengcheng Formation in the Junggar Basin, China, was investigated using the geochemistry of heteroatomic species, with a focus on N-containing compounds, by negative-ion electrospray high-resolution Fourier transform ion cyclotron resonance mass spectrometry. The maturity parameters based on N-containing compounds (e.g., C0–5/C15–35-DBE 12 N1 and C0–5/C15–35-DBE 15 N1) and aromatic hydrocarbons (TMNr) reveal progressive generation of mature to highly mature crude oils. The polymerization index P1 ([DBE 18 + DBE 15]/DBE 12_N1), alkylation index R1 (RC6−35/RC0−5), and paleo-salinity index (β carotane/nCmax) of the Fengcheng Formation source rocks suggest that the high salinity inhibited molecular polymerization of organic matter and prolonged the oil generation peak, which produced highly mature crude oils in the late stages of hydrocarbon generation. Therefore, alkaline lacustrine source rocks undergo multiple stages of protracted oil generation, which results in a longer oil window and higher threshold for gas generation than in the case of the classic Tissot model. The results highlight the oil generation potential of deep basins containing alkaline lacustrine source rocks and highly mature organic matter, which also have a lower gas-generation potential than previously thought.

Hydrocarbon Generation History of the Eocene Source Rocks in the Fushan Depression, South China Sea: Insights from a Basin Modeling Study

Reconstruction of hydrocarbon generation history is essential to understanding the petroleum system. In this study, basin modeling was employed to investigate the primary source rocks in the Fushan Depression (FD), a significant oil-bearing basin situated in the South China Sea. The research findings indicate that different tectonic zones within the FD underwent distinct hydrocarbon generation stages. The step-fault zone and the central sag zone experienced one hydrocarbon generation stage at 10–0 Ma and 30–0 Ma, respectively. The slope zone, on the other hand, experienced two hydrocarbon generation stages, 40–23.5 Ma and 10–0 Ma, controlled by tectonic movements and heat flow variations. Furthermore, critical times for the process of the petroleum system have been determined based on this work and previous literature. The slope zone in the eastern FD is considered a favorable area for conventional hydrocarbon exploration due to the high maturity of source rocks promoted by volcanic heating and two significant oil charges. The central sag zone is identified as an excellent prospect for unconventional resources because of the substantial retention of hydrocarbons in in-source unconventional reservoirs long after hydrocarbon generation. These findings provide a valuable guide for further exploration.

Revealing continuous hydrocarbon generation and shale oil accumulation of saline lacustrine source rocks by sequential extraction

Saline lacustrine fine-grained rocks are important hydrocarbon source rocks and host large shale oil accumulations worldwide. However, the specific process and mechanism of hydrocarbon generation and accumulation in such rocks are not clear. Sequential extraction is a method to chemically separate different hydrocarbon fractions in sedimentary rocks, commonly as free, adsorbed and retained hydrocarbons, and thus can theoretically record the entire process of hydrocarbon generation and accumulation. To test this hypothesis, here sequential extraction was carried out on source rock samples with varying maturities from the alkaline lacustrine strata of the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. The 17β-ethylandrostane/C29-sterane ααα20R and tricyclic terpane/pentacyclic triterpane ratios vary with maturity. In contrast, some biomarker parameters are not significantly affected by thermal maturity, including pristane/phytane, β-carotane index (β-carotane/main peak n-alkane), sterane/hopane, 7-+8-methyl index (7-+8-monomethyl heptadecane/main peak n-alkane), and C28/C29 regular sterane values, and can thus be used for oil–source rock correlations. The low-maturity source rocks have undergone one stage of hydrocarbon generation and associated shale oil accumulation, whereas source rocks with relatively high maturity have experienced multi-stage hydrocarbon generation and associated shale oil accumulation. In the early stages, cyanobacteria were the main bioprecursor to hydrocarbons and, with increasing maturity, Dunaliella gradually became the more important bioprecursor. Hydrocarbon generation by these alkaline lacustrine source rocks involved multiple sources and stages, which accounts for the abundant shale oil resources in the Mahu Sag with one-billion-ton reserves. This might be general for saline lacustrine source rocks worldwide, which can generate both conventional and unconventional hydrocarbons in large scales. Compared with conventional thermal modeling to constrain the generation history of hydrocarbon source rocks, a unique advantage of sequential extraction is its ability to characterize the entire history of hydrocarbon generation under geological conditions.

Microindentation analysis of mechanical properties evolution during an artificial hydrocarbon generation process

The last decade witnessed rapid growth of shale oil and gas production. Increasing numbers of shale reservoirs have been explored and developed. Since hydrocarbon generation is an important process in forming a shale reservoir, it has attracted great attention from researchers. However, previous works mainly focus on geochemical changes during the hydrocarbon generation process, and investigations of the change of other parameters are insufficient. In this study, we intend to fill this gap in the literature by examining the mechanical properties evolution of organic-rich shales during an artificial hydrocarbon generation experiment. Continuous stiffness measurement (CSM) and microindentation test are used to measure the mechanical properties of rocks. The result of CSM shows the influence of indentation depth on Young's modulus. Three stages are identified, and a displacement of 4000 nm–6000 nm is determined to be appropriate for measuring bulk mechanical properties. Microindentation results of shales at different hydrocarbon generation stages exhibit a hill-like trend. The Young's modulus with an initial value of 42.15 GPa increases as the hydrocarbon generation proceeds, reaches a maximum value of 46.49 GPa, and then begins to decrease and reaches the lowest value of 37.41 GPa. Indentation hardness and estimated fracture toughness by an energy-based method show similar trends to Young's modulus. Scanning electron microscope observation of post-hydrocarbon-generation samples may provide an explanation of the hill-like trend.

Oligocene source-rock characteristics and hydrocarbon generation modeling of the eastern Nile delta, Egypt

This study investigates Oligocene source rock development in the eastern Nile Delta, integrating TOC, Rock-Eval pyrolysis, as well as vitrinite reflectance (Ro%) measurements from over 9 onshore and offshore wells. 1D basin models, constructed for 2 wells onshore and 2 wells offshore, investigate the burial, thermal histories, and the stage and timing of hydrocarbon generation. The present-day data indicate that the Oligocene section encompasses Type III and rarely Type IV kerogen onshore, whereas offshore Type III and Type II-III kerogen dominate. The back-calculated original TOCo and HIo values indicate a significant hydrocarbon generation (i.e. effective to relic source rock) for Rupelian section in Tayifah Deep-1x and Satis-1 wells. The different maturity indicators used here show significant differences in some intervals. The variability may be attributed to natural impregnation of migrated hydrocarbon in permeable strata, in-situ expelled hydrocarbons where S2 contamination is rather likely for samples within the oil window, or retarded Ro% and/or Tmax caused by overpressure. Therefore, thermal and generation models are calibrated with measured bottomhole temperatures, which match quite well with δ13C values of gases C1-3, and indicate that the onshore Oligocene basal section comes in the early stage of hydrocarbon generation throughout the middle-late Miocene, and was in the main stage of hydrocarbon generation since the early Pliocene. The transformation ratio indicates an in-situ expulsion (25–50%) since the Pleistocene time. Offshore models indicate the basal Oligocene section entered the late phase of hydrocarbon generation during the early to middle-late Miocene, where its transformation ratio exceeds 50%. This indicates the main hydrocarbon expulsion from the late Oligocene to the early-middle Miocene time. Further integrated approaches to the Oligocene geochemical analysis after solvent extraction are vastly required. Higher resolution overpressure and maturity indices (Tmax and Ro) profiles for some deep sections are essential to strengthen concepts about the mechanism(s) and magnitude of their retardation/suppression.

Organic Geochemical Characteristics and Organic Matter Enrichment of the Upper Permian Longtan Formation Black Shale in Southern Anhui Province, South China.

Although previous studies have yielded valuable insights into shale gas reservoirs, a comprehensive understanding of the organic geochemical characteristics and organic matter enrichment of marine-continental transitional shale has yet to be achieved. The Longtan Formation transitional shales were extensively deposited in Southern Anhui Province, South China, during the Late Permian. Our analysis of twenty-two rock samples from one core (Gangdi-1 well) and two outcrops (Daoshanchong outcrop and Changqiao outcrop) revealed that the Longtan Formation shale extracts exhibit a wide range of C11-C35n-alkanes and acyclic isoprenoids, with unimodal, bimodal, and multimodal distributions. The carbon peak ranges from nC15 to nC24, with high quantities of medium-chain n-alkanes (nC22-nC25), indicating that the organic matter in Longtan Formation shale originates from a mixed source of higher plant debris and lower aquatic organisms. Our conclusion is supported by the ternary diagram of C27-C28-C29 regular steranes and the variations of the δ13C values of C15-C32n-alkanes, which is higher than the corresponding value (<1.6‰) of n-alkanes from a single source. Furthermore, thermal maturity proxies based on organic petrography (Ro and Tmax) and biomarkers, such as the ratios of C31 22S/(22S + 22R), C29 20S/(20S + 20R), and C29 ββ/(αα + ββ), suggest that organic matter is in a mature stage of hydrocarbon generation. By analyzing the Pr/Ph ratio and pyrite morphology combined with a plot of total organic carbon (TOC) versus total sulfur (TS) and the Pr/nC17-Ph/nC18 diagram, we speculate that the Longtan Formation shales were chiefly developed in a dysoxic-to-oxic water environment. Finally, we establish depositional models of organic matter enrichment in deltaic and tidal flat-lagoon environments, emphasizing that the abundant mixed-sourced organic matter can significantly enhance primary productivity, and a higher sedimentation rate can distinctly shorten organic matter exposure time in the oxidized water environment, thereby promoting organic matter accumulation in such a setting.

Hydrocarbon Generation Mechanism of Mixed Siliciclastic–Carbonate Shale: Implications from Semi–Closed Hydrous Pyrolysis

Affected by the complex mechanism of organic–inorganic interactions, the generation–retention–expulsion model of mixed siliciclastic–carbonate sediments is more complicated than that of common siliciclastic and carbonate shale deposited in lacustrine and marine environments. In this study, mixed siliciclastic–carbonate shale from Lucaogou Formation in Junggar Basin was selected for semi–closed hydrous pyrolysis experiments, and seven experiments were conducted from room temperature to 300, 325, 350, 375, 400, 450, and 500 °C, respectively. The quantities and chemical composition of oil, gases, and bitumen were comprehensively analyzed. The results show that the hydrocarbon generation stage of shale in Lucaogou Formation can be divided into kerogen cracking stage (300–350 °C), peak oil generation stage (350–400 °C), wet gas generation stage (400–450 °C), and gas secondary cracking stage (450–500 °C). The liquid hydrocarbon yield (oil + bitumen) reached the peak of 720.42 mg/g TOC at 400 °C. The saturate, aromatic, resin, and asphaltine percentages of bitumen were similar to those of crude oil collected from Lucaogou Formation, indicating that semi–closed pyrolysis could stimulate the natural hydrocarbon generation process. Lucaogou shale does not strictly follow the “sequential” reaction model of kerogen, which is described as kerogen firstly generating the intermediate products of heavy hydrocarbon compounds (NSOs) and NSOs then cracking to generate oil and gas. Indeed, the results of this study show that the generation of oil and gas was synchronous with that of NSOs and followed the “alternate pathway” mechanism during the initial pyrolysis stage. The hydrocarbon expulsion efficiency sharply increased from an average of 27% to 97% at 450 °C, meaning that the shale retained considerable amounts of oil below 450 °C. The producible oil reached the peak yield of 515.45 mg/g TOC at 400 °C and was synchronous with liquid hydrocarbons. Therefore, 400 °C is considered the most suitable temperature for fracturing technology.

Decipher hydrocarbon generation and accumulation based on fluid inclusion and chronology: A case study from the Upper Paleozoic buried-hills in Huanghua Depression, Bohai Bay Basin

Deciphering hydrocarbon generation and accumulation stage is of significance to understand oil and gas evolution and seek exploration targets. Taking the Upper Paleozoic buried-hills in the Huanghua Depression, Bohai Bay Basin, as a case study, hydrocarbon generation environment and detailed accumulation process are revealed by fluid inclusions observations, Laser Raman spectroscopy, Fourier Infrared spectroscopy, and K–Ar isotope measurements. The results show that both oil and gas inclusion were captured in the quartz overgrowth, dissolved feldspar and calcite microfractures, showing blue to dark brown fluoresce. The grains containing oil inclusions index (GOI) of oil, oil & gas and gas being 25%, 65%, and 10% and the inclusions with abundant methyl groups and short chains, both indicate high thermal maturity. One series of fluids inclusion is generally observed, evidenced by the concentrated homogenization temperature of 135–145 °C and salinity of 3%–15 w.t.% NaCl equiv, indicating one primary charging stage. The gas and gas & liquid inclusions mainly contain CH4, with also peaks indicating CO2 and N2. The Carboniferous and Permian biomarkers show reducing environment with brackish water, with organic matter sources both from marine and continental. The relative content of ααα20RC27, ααα20RC28, and ααα20RC29 exhibit source contributions both from algae and higher plants, and mainly of II2 to III kerogen. Both coal derived gas and oil associated hydrocarbons are identified from most of the buried-hills. Combining the fluid homogenization temperature and salinity, as well as the thermal evolution history, the hydrocarbon generated from the Upper Paleozoic was concentrated at the end of the Eocene (40 Ma±), while the beginning of charging is 60 Ma±. The Wumaying Buried-hill is of only coal derived gas and has potential for inner coal measure natural gas exploration. The results provide a detailed understanding of hydrocarbon accumulations in the study area, which can also be reference for improving petroleum exploration efficiency in similar basins.

Application of biomarkers in characterization of organic matter source, maturity and palaeoredox condition of black shales from the upper Permian Dalong Formation in Southern Anhui Province, South China

The organic‐rich shale in the upper Permian Dalong Formation in Southern Anhui Province is not only regarded as a high‐quality hydrocarbon source rock, but one of the potential targets for shale oil and gas exploration in Southern China. Organic matter types in such a setting remain a subject of debate. The major point of controversy is whether they are dominated by oil‐prone types or gas‐prone types. A total of 20 rock samples collected from Gangdi‐1 well were conducted for analysis of organic geochemistry. Results show that Dalong Formation shale extracts exhibit a wide range of C12‐C35 n‐alkanes and acyclic isoprenoids. The chromatograms display an unimodal distribution with carbon peak in the range of nC18‐nC22 and low quantities of long‐chain (nC25+) n‐alkanes. Relatively high ratios of nC21‐/nC22+ and C27/C29 regular steranes demonstrate that organic matter is mainly originated from lower aquatic organisms and followed by higher plants in a local area. This is also supported by the variations of the δ13C values of C13‐C26 n‐alkanes for the target samples being in the range of 3.0‰–5.6‰ offset, which is slightly higher than the corresponding value (1.6‰) of n‐alkanes from a single source. All these pieces of information decipher that the organic matter in Dalong Formation shale may be dominated by type I and followed by type II1. Moreover, the maturity proxies according to both organic petrography (Ro and Tmax) and biomarkers such as ratios of C29 20 S/(20 S + 20R) and C29 ββ/(αα + ββ) together indicate that organic matter in Dalong Formation shale is in a mature stage of hydrocarbon generation. Furthermore, a cross‐plot of total organic carbon versus total sulphur as well as Pr/Ph ratio and Pr/nC17‐Ph/nC18 diagram elucidates that Dalong Formation shales were mainly formed in a marine reducing environment. Finally, two depositional models of organic matter enrichment are proposed. The abundant lower aquatic organisms with few terrestrial detrital inputs and the reducing water environment together promote organic matter accumulation.

Differences in geochemistry and hydrocarbon generation of source-rock samples dominated by telalginite and lamalginite: A case study on the Permian saline lacustrine source rocks in the Jimusaer Sag, NW China

The Middle Permian Lucaogou Formation in Northwestern China mainly contains typical saline lacustrine oil shale. To study the differences in geochemistry and hydrocarbon generation of source-rock samples in Lucaogou Formation in Jimusaer Sag, 57 core samples from two boreholes were analyzed herein by performing total organic carbon (TOC) analysis, Rock–Eval pyrolysis, and gas chromatographic–mass spectrometry experiments on saturated hydrocarbons. The kinetics of oil generation were studied using two samples comprising typical maceral components. The results showed that the hydrocarbons produced by telalginite are relatively rich in pristane (Pr), phytane (Ph), β -carotane, high-carbon normal alkanes, and C 29 regular steranes. Hydrocarbons produced by lamalginite contain a significantly higher content of C 20 tricyclic terpanes (TT), C 21 TT, C 24 tetracyclic terpanes (TeT), C 29 norhopane, and C 28 regular sterane. Based on the pyrolysis and biomarker compound parameters, telalginite has a higher conversion rate for hydrocarbons than lamalginite in the low-mature to mature stage, which is consistent with their kinetic analysis. Lamalginite source rock display a much narrower distribution of activation energies than telalginite source rocks; Such narrower activation energy distribution effectively narrows the main stage of hydrocarbon generation. In addition, the activation energy distribution of lamalginite is concentrated in the high-value interval, indicating the characteristics of the relatively lagging hydrocarbon generation of lamalginite.

Tectonic evolution and its control on oil–gas accumulation in southern East China Sea since the Jurassic

Based on the results from the previous research on Mesozoic igneous rocks, as well as tectonic environments in the northern South China Sea and southern East China Sea (NSCS-SECS), geophysical parameters, strata, and characteristics of seismic facies in NSCS-SECS were investigated. These findings were combined with results from the analysis of the balanced profile evolution to re-evaluate the tectonic evolution of SECS since the Jurassic. Furthermore, burial history and simulation of wells in the SECS were analyzed using well, seismic and source rock data. Furthermore, favorable models of oil–gas accumulation in the Lower–Middle Jurassic were proposed in combination with studies on elements and conditions of the petroleum system. The results demonstrated that the NSCS-SECS had consistent tectonic settings and comparable strata from the Jurassic to the Cretaceous time. There was a large unified basin in this period. The basin experienced two evolutionary stages, respectively, the fore-arc depression basin in the Early–Middle Jurassic (J1-2) and the back-arc faulted basin in the Late Jurassic–Cretaceous (J3-K). There was considerable deposition of dark mudstones in the SECS during the Lower–Middle Jurassic. The Keelung Sag was the depositional center accumulating the thickest section of the Lower–Middle Jurassic source rocks which entered a high-maturity stage. Hence, it was the hydrocarbon generation center in the SECS. The process of generating hydrocarbons from Lower–Middle Jurassic source rocks was of high complexity from northwest to southeast. The Lower–Middle Jurassic source rock at the northwest edges of the basin experienced two hydrocarbon generation stages, while the Keelung Sag toward the southeast experienced three hydrocarbon generation stages. The models and types of oil–gas accumulation in various evolutionary phases were different due to the control by tectonic evolution. Oil and gas that were generated by Lower–Middle Jurassic source rocks in the Keelung Sag migrated and accumulated in the western high-tectonic units. Research findings provide insights into Mesozoic oil and gas exploration in the NSCS-SECS.

Geochemical Characteristics of the Chang 7 Source Rocks of the Triassic Yanchang Formation in Ordos Basin, China: Implications for Organic Matter Accumulation and Shale Oil Potential

The Chang 7 member of the Upper Triassic Yanchang Formation in the Ordos Basin is considered to hold the main source rocks for conventional and unconventional oil and gas. The lamination or lithology alteration in vertical and lateral directions, even over a short distance, is a common feature in lacustrine source rocks. The differences in the geochemical characteristics of black shales, dark mudstones and interbedded sandstones have been scarcely reported, and their influences on the petroleum generation potential and shale oil potential are not clear. To this end, 22 core samples were collected from the Lower and Middle Chang 7 (C7-3 and C7-2) members of the Triassic from well CYX in the Qingcheng area. By conducting a series of geochemical analyses including TOC, Rock-Eval pyrolysis yields, bitumen extraction and quantification, and the separation and quantification of saturates, aromatics, resins and asphaltenes, along with biomarker analyses, several results were found. Firstly, the C7-3 and C7-2 source rocks are thermally mature and have entered into the stage of hydrocarbon generation. The C7-3 and C7-2 source rocks have a good to very good hydrocarbon generation potential especially the C7-3 black shales. Secondly, terrigenous source input is more abundant in C7-2, whereas the source input of phytoplankton, algae or microbial lipids is more abundant in C7-3. Moreover, a high TOC content basically corresponds to low wax indexes, terrigenous/aquatic ratios (TARs), and Pr/nC17 and Ph/nC18 ratios and high C27/C29 regular sterane ratios, which suggests that the source input of phytoplankton, algae or microbial lipids is favorable for OM accumulation. Third, analyses of the molecular composition of saturated fractions in shales and interbedded sandstones and the production index demonstrate the migration of petroleum from organic-rich source rocks to their organic-lean counterparts. The C7-2 dark mudstones could be considered as a potential “sweet spot” since their oil saturation index (OSI) was the highest among all the studied samples and they are more enriched in light aliphatic fractions.

Origin, Depositional Environment and Thermal Maturity of some Source Rocks from Niger Delta Basin, Nigeria

Eleven (11) core samples from Agbada and Akata formations in the Niger Delta, Nigeria, were analyzed using gas chromatography-mass spectrometry to evaluate their paleodepositional conditions and source input as well as to determine their thermal maturity. The distribution of n-alkanes, isoprenoids, and biomarkers indicate a mixture (marine/terrigenous) organic matter source input for Agbada and Akata formation sediments deposited in marine environment. Low values of Phytane/nC18 (0.45 to 1.32) and Pristane/nC17 (0.37 to 1.8) indicates Marine organic matter contribution and anoxic-suboxic (Type II/III kerogens) depositional conditions of extract for Agbada and Akata Formations. The Carbon Preference Index (CPI) values for all analysed samples are slightly greater than 1.0 indicate a mixed input of marine and terrigenous organic matter deposited under relatively reducing (dysoxic) conditions. The high concentration of Oleanane in studied samples reveals that source rocks are tertiary age and belong to marine deltaic depositional environment. Moderate to higher Gammacerane index values ranging from 0.06 to 0.11, suggests water-column stratification, potentially due to hypersalinity for Isan oilfield well samples from Agbada formation. Biomarker maturity parameters suggest that the sediments have reached the early stages of hydrocarbon generation.

Thermoacoustic emission characteristics and real-time damage evolution in shales of the Lower Palaeozoic Niutitang Formation

Identifying shale geological temperatures is important for understanding the thermal maturity, thermal evolutionary history, and hydrocarbon generation stages of shale formations, and enables efficient shale gas development. This paper investigates the thermal Kaiser effect of shales under different warming rates by studying the thermoacoustic emission (TAE) characteristics of shales in the Lower Palaeozoic Niutitang Formation in the Micangshan area of China. The developmental evolution and microscopic response mechanisms of different types of fractures in shales under high-temperature conditions are explored by combining acoustic emission (AE) characteristic parameters. The memory and sensitivity of the thermal Kaiser effect were also verified by thermal fatigue tests. The results show that there is a significant thermal Kaiser effect during the heating of shale and that its threshold temperature is approximately 180 °C, which is consistent with the palaeotemperatures based on bitumen reflectance (Rb) estimation. The heating rate does not have a significant effect on the threshold temperature. At high temperatures, the shale is dominated by small-scale tensile fractures. When the shale is heated to 300 °C, the organic matter reaction rate peaks and the proportion of shear cracks begins to increase. An increase in heating rate is beneficial to the development of large-scale tensile cracks, while inorganic minerals begin to expand due to heat and micro-cracks gradually expand and connect, thus improving the connectivity of the pore channels. In thermal fatigue tests, the shale retains its memory of the threshold temperature when heated to less than 300 °C. Above 300 °C, pyrolysis of organic matter and microcrack expansion interfere with the thermal Kaiser effect, causing the shale to lose its memory of the maximum temperature. Within the same cycle stage, the threshold temperature is significantly higher at high heating rates than at low ones, especially above 400 °C.