Source Rock Samples Research Articles

Assessing hydrogen production potential from carbonate and shale source rocks: A geochemical investigation

The global push towards achieving net-zero carbon dioxide emissions by 2050 shows the urgency of transitioning to a hydrogen-based economy, with clean hydrogen fuel emerging as a fundamental component of future energy consumption. This study explores hydrogen production from geological sources, specifically organic-rich Shale and Carbonate mudrocks, as a significant and sustainable method for natural hydrogen production. Recognizing the critical challenge posed by the interaction of hydrogen with rock-forming minerals and organic matter during production, this research emphasizes the need for a comprehensive understanding of the geochemical composition of these rock materials. To assess the feasibility and implications of utilizing organic-rich source rocks for hydrogen production, we conducted thorough analyses of source rock samples from different formations. The representatives’ samples were subjected to comprehensive analyses including Rock-Eval pyrolysis, X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscope (SEM) examinations, and gas chromatography (GC) analysis of the produced gas. Our results revealed that the high total organic carbon (TOC) samples (average 14.7 %) with Type I and II kerogens yielded substantial hydrogen-rich gases, approximately 44.71 % and 36.02 % for SH-O1 and JOS samples, respectively. JOS produced slightly higher hydrocarbon gases (∼50 %) compared to SH-O1 (∼45 %), along with more H2S (5.78 %), due to higher total sulfur content. In contrast, the SH-C1 sample, characterized by very low TOC (0.27 %), predominantly quartz and muscovite minerals (>78 %), and Type IV kerogen, produced higher CO2 (22.09 %) and minimal hydrogen (1.27 %), highlighting the influence of mineralogical and geochemical composition. This study suggests that hydrocarbon source rocks with high organic matter content hold significant potential for maximizing energy gas recovery (>85 %, including hydrogen and hydrocarbons) through the pyrolysis of their kerogen content. These findings demonstrate the viability of hydrogen gas production from unconventional sources such as organic-rich shales, potentially impacting strategies for sustainable energy production and contributing significantly to global decarbonization efforts.

A new method to quantify the source contribution of mixed biodegraded oil based on pareto-optimized nonnegative matrix factorization and chord diagram visualization

The biogenic information of different components in crude oils with varying degrees of biodegradation is partially obscured, making traditional molecular indicators ineffective in determining the contributions of mixed sources. Previous studies have mainly focused on calculating mixed source proportion for normal oils, with few investigations involving biodegraded mixed oils. Developing a quantitative method for the mixed source contribution of biodegraded oils using machine learning (ML) algorithms is a significant attempt both to the exploration practice and theoretical progress. Taking the biomarker parameters resistant to biodegradation of 150 oil samples as input datasets, a new method called Pareto-Optimized NMF (PONMF) was proposed in this study, which combines multi-objective optimization (Pareto optimization) with non-negative matrix factorization (NMF) to analyze the relationship between biodegraded oils in the absence of source rock samples or original end-member (EM) oils while satisfying non-negativity constraints and additional constraint conditions. This method decomposes the matrix of crude oil samples into multiple end-members, each representing a possible input from a hydrocarbon source rock. Analysis of the end-member characteristics facilitates the deduction of potential hydrocarbon source layers and the traits of their depositional environments. This examination is supported by data derived from 15 prospective hydrocarbon source rock samples, which were employed to ascertain the actual geological significance of the end-members. The chord diagram depicts the visualization results of the overall relative contribution of source rock end members to crude oil in each area after the PONMF calculation results. The relative contribution of source rocks in different areas to the investigated crude oil samples is proportionate, and the arc length can reflect the contribution of the three sets of source rocks to a certain area. The findings indicate that the oils extracted from the stratified reservoirs in Eastern Chepaizi are primarily derived from the Permian source strata within the Shawan Depression, with a significant contribution ranging from 30% to 90% (EM2), and a lesser extent from the Carboniferous sources, contributing between 5% and 30% (EM1). Conversely, the provenance of oil in Western Chepaizi is overwhelmingly attributed to the Jurassic source interval located in the Sikeshu Depression, where EM3 accounts for over 85% of the source. Meanwhile, the oils in the Central Zone exhibit a composite origin, intermingling contributions from both EM1 and EM3. The advantage of this method is that it does not require direct access to hydrocarbon source rock samples or end-member oils but infers potential hydrocarbon source layers through the existing mixed-source oil samples. The PONMF method provides an effective tool for identifying the sources of biodegraded oils and can be used to study potential hydrocarbon source rock analysis for oils that have undergone biodegradation after hydrocarbon accumulation.

Determine Oil and Water Saturations in Preserved Source Rocks From 2D T1-T2 NMR

Two-dimensional (2D) T1-T2 NMR has been widely proposed as a method to determine the fluids present in unconventional source rocks. However, the assignment of the components in the 2D T1- T2 NMR spectra has so far been based on conceptual consideration and lacks rigorous experimental verification. Many assignment variations appeared in the literature and can be misleading. For example, large T1/T2 peaks in the 2D T1-T2 NMR were suggested to be fluid in small pores coupled with kerogen solid through dipolar relaxation. Our recent 500-MHz NMR relaxation experiments found that the dipolar relaxation between nanoconfined fluids and solid matrix is not big enough to support that large T1/T2 interpretation. The objective of this paper is to determine what quantitative data can be obtained using 2D T1-T2 NMR from source rocks with high confidence. We found the oil and water saturation can be accurately measured in preserved source rock plugs. Two-dimensional T1-T2 NMR data were collected on preserved core plugs from five wells of a source rock reservoir using an inversion-recovery Carr-Purcell-Meiboom-Gill (CMPG) pulse sequence on a 12-MHz NMR instrument. The acquired 2D data were inverted using an optimized inversion software, MUPen2D. We then obtain oil and water content in the plug from the 2D T1-T2 NMR using an in-house-developed NMR MATLAB app. The porosity of all the plugs was measured using a combined NMR and gas porosimetry (CNG) method. Oil and water saturation were also obtained using an industry-standard method developed by the Gas Research Institute (GRI) on the rock material close to where the plug was drilled. The oil and water saturations measured on the preserved plugs using 2D T1-T2 NMR and CNG are consistent with those from the GRI method using crushed rocks and an invasive cleaning procedure. The results show that oil and water saturations were accurately determined from 2D T1-T2 NMR on preserved source rock samples with high confidence. The NMR method is nondestructive and noninvasive and takes less than 4 hours on a preserved source rock plug, while GRI is destructive and invasive and can take several weeks for an accurate measurement on one sample. The measured results can be further used to determine the production potential of a source rock well in combination with log data.

Investigation of Hydrocarbon Generation from Jurassic Coal Measures in the Southern Junggar Basin, Northwestern China, Using Closed-System Pyrolysis.

There are several sets of coal-bearing source rocks within the Lower and Middle Jurassic (J1-2) in the southern Junggar sub-basin. To obtain a comprehensive understanding of hydrocarbon generation and the amount of potentially generated natural gas, Rock-Eval analysis was conducted on source rock samples to assess their kerogen types and quality. At the same time, maceral observation and gold-tube pyrolysis were carried out to quantify the different maceral groups and to predict the gas potential, respectively. The Rock-Eval data indicate that the investigated samples are dominated by type III kerogen and occasionally supplemented with type II kerogen. Among the six immature source rocks selected for gold-tube pyrolysis, they are vitrinite-dominated except for a dark mudstone from the Badaowan Formation that is liptinite-dominated. A positive relationship between the maximum gas yield and the liptinite content was observed. However, the accuracy of liptinite content estimation largely depends on the experience level of the organic petrographer. The optimized C1-5 generation activation energies for the six source rocks cover a broad range between 50 and 74 kcal/mol. A relatively larger proportion of higher activation energies (74 kcal/mol) for the carbonaceous mudstone from the Badaowan Formation and also for the dark mudstone from the Sangonghe Formation implies late gas generation. Under geological conditions, the modeled gas conversion from J1-2 source rocks in the central part of the southern Junggar sub-basin ranged from 52 to 74%, indicating good exploration potential. Notably, the computed gas generation from the dark mudstone from the Sangonghe Formation resembles that from the Xishanyao Formation. Gas generation from the Sangonghe Formation should be considered in the future.

Oxidative Hydraulic Fracturing Fluid to Enhance Production from Source Rock Reservoirs

Summary The steep production declines generally observed after hydraulic fracturing in unconventional source rock reservoirs has been attributed to several potential causes. Recently, a new additive to the stimulation fluid system was proposed to extend economical longer-term production from these formations. Oxidizer-laden fracturing fluid systems are shown to create cracks and deep channels within the organic matter present in the source rock, such as kerogen, thereby increasing the source rock permeability and enhancing the hydraulic conductivity of the exposed fracture faces. To this end, the fluid design and recommendations for its application are illustrated herein. Oxidants composed of oxychlorine (ClOn−) and oxybromine (BrOn–) (where n = 0 to 4) are effective for kerogen depolymerization or degradation at depth. This study illustrates the beneficial effects of two specific oxidizers—sodium chlorite (NaClO2) and sodium bromate (NaBrO3)—on kerogen-rich source rock subjected to in-situ reservoir conditions. Source rock samples were cut and polished to test the oxidizer’s impact on the organic and inorganic regions. Scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS) were performed on the rock surface to identify specific organic matter features. The samples were then chemically treated with varying conditions of NaClO2 or NaBrO3 (concentration range: 0.013–0.054 M; temperature: 150°C; and time: 3–24 hours). Samples were returned to the scanning electron microscope for post-treatment analysis. Furthermore, the oxidants were packaged within a slickwater hydraulic fracturing fluid system for field application, and their effects on viscosity and friction reduction were also studied. SEM images and EDS maps of kerogen-rich rock samples observed before and after treatment with oxidizing fluid showed a series of cracks formed throughout the organic matter domains, where increasing the concentration of oxidizer in the treatment fluid showed a clear increase in the prevalence of cracks throughout the surface. The effect of time was also observed, as short treatment times resulted in porosity/permeability creation in the kerogen, though longer treatment times were associated with more severe degradation. Optimal conditions for NaClO2 and NaBrO3 concentrations in the additive fluid systems were different and will be herein highlighted. Each oxidizer (10–20 pptg concentration) was added to slickwater with variable friction reducer concentration (1 gpt, 2 gpt, and 4 gpt), and shear sweeps performed at both 70°F and 180°F. A negligible difference is observed between the viscosities of the base fluid and the fluid with either oxidant at low friction reducer concentration. Meanwhile, flow loop tests demonstrated that the oxidizer did not affect the friction reducer except to slightly boost the performance due to the salt effect on the polymer. Two strong oxidants, available as commodity chemicals, are shown to be effective in cracking kerogen and any present organic matter, thus creating permeable channels and enhancing the overall permeability of the exposed source rock fracture faces. Meanwhile, the proposed fracturing fluid additives display good compatibility with other slickwater fluid components, demonstrating the potential for universal usage in unconventional stimulations. The recommendations for its application as a fluid additive in slickwater are herein illustrated.

Petroleum Potential Prospectivity of Muglad Basin, South Sudan: A Case of Source Rocks Characterisation in the Drilled Kaikang West-1 Well

This study focuses on Prospectivity of Petroleum Potential of Muglad basin, South Sudan, with the help of petroleum source rocks characterisation in the drilled Kaikang West-1 Well based on the organic matter quantity, quality, and the thermal maturation generation capability of the organic matter disseminated in the analysed rock samples. Muglad basin is a major petroliferous Western and Central African Rifts System (WCARS) member, with estimated reserves of 2,053 mm bbl. Muglad Basin comprises thick sandstones of Aradeiba and Bentiu Formations, considered to be the main petroleum prospectivity targets, with trapping mechanism being structural faults and lithological anticlines. The organic matter contents were determined directly from laboratory analyses of the source rock samples with the help of seismic and gamma ray profiles, total organic carbon (TOC wt %), maturity indices (OI, HI and PI), temperature maximum (Tmax °C), porosities and other sedimentological parameters. This study involved a series of analytical geochemistry and petro-physical studies to ascertain a number of effective source rock samples from the well cores which were then analysed in terms of TOC, OI, PI, HI, S2, S1 and Tmax to determine oil/gas prone samples (resource areas). These were then distinguished from strata with very high organic matter samples as well as very high TOC to help identify for possible source rock characterizations within the lithology pertaining to the well in terms of potential source-reservoir-seals combinations. The Rock-Eval pyrolysis data were useful in assessing and evaluating the type of organic matter, thermal maturity, and the generation capability of source rocks for hydrocarbon exploration rationale. The analyses revealed that some strata, within the sampled well data, have high hydrocarbon generation potential with the existence of commercial hydrocarbon production

Multiple enrichment mechanisms of organic matter in the Fengcheng Formation of Mahu Sag, Junggar Basin, NW China

Based on core and thin section data, the source rock samples from the Fengcheng Formation in the Mahu Sag of the Junggar Basin were analyzed in terms of zircon SIMS U-Pb geochronology, organic carbon isotopic composition, major and trace element contents, as well as petrology. Two zircon U-Pb ages of (306.0±5.2) Ma and (303.5±3.7) Ma were obtained from the first member of the Fengcheng Formation. Combined with carbon isotopic stratigraphy, it is inferred that the depositional age of the Fengcheng Formation is about 297–306 Ma, spanning the Carboniferous–Permian boundary and corresponding to the interglacial period between C4 and P1 glacial events. Multiple increases in Hg/TOC ratios and altered volcanic ash were found in the shale rocks of the Fengcheng Formation, indicating that multiple phases of volcanic activity occurred during its deposition. An interval with a high B/Ga ratio was found in the middle of the second member of the Fengcheng Formation, associated with the occurrence of evaporite minerals and reedmergnerite, indicating that the high salinity of the water mass was related to hydrothermal activity. Comprehensive analysis suggests that the warm and humid climate during the deposition of Fengcheng Formation is conducive to the growth of organic matter such as algae and bacteria in the lake, and accelerates the continental weathering, driving the input of nutrients. Volcanic activities supply a large amount of nutrients and stimulate primary productivity. The warm climate and high salinity are conducive to water stratification, leading to water anoxia that benefits organic matter preservation. The above factors interact and jointly control the enrichment of organic matter in the Fengcheng Formation of Mahu Sag.

Quality and composition of Lower Cretaceous carbonate source rocks and seepage oils in the Belize Basin, southern Belize, Central America

The Belize Basin in southern Belize, Central America, contains numerous seepage oils derived from marly and carbonate source rocks, but since no definitive source rocks have been identified the source remains uncertain. This study examines by pyrolysis and organic petrography the source rock quality and maturity of 66 samples collected from three newly exposed carbonate sections in the southeastern Belize Basin together with organic geochemical analysis of five new occurrences of seepage oils from the southern Belize Basin. Combined ammonite and aptychi biostratigraphy suggest a Berriasian to Hauterivian age of the source rock samples. Low Tmax values show the samples are thermally immature. Numerous samples are oil-prone and have Hydrogen Index values >300–400 mg HC/g TOC, reaching a maximum of 768 mg HC/g TOC. The samples with source rock potential contain from 32 to 64% pyrolysable organic carbon and contains liptinite-rich Type II kerogen consisting of alginite, bituminite, and liptodetrinite. The calculated Ultimate Expulsion Potential (UEP) of a 22.5 m thick section amounts to ∼2.5 mmboe/km2. This generation capacity is volumetrically relatively small, but it could be compensated for by a thicker source rock section. However, the identified source rocks could account for the seepage oils in the Belize Basin, and they are thus the first documentation of Lower Cretaceous source rocks in Belize. A plausible explanation for the widespread occurrence of seepage oils in the Belize Basin could be generation from organic-rich layers with bituminite and alginite. In line with this and previously examined seepage oils, the new variably degraded oils were sourced from carbonate source rock facies.

Effect of Ancient Salinity on the Distribution and Composition of Tricyclic Terpane in Hydrocarbon Source Rocks in the Mahu Depression

Ma2 and Ma3 hydrocarbon source rock samples from the Fengcheng Formation in well Maye 1, Mahu Depression, Junggar Basin, were studied using conventional geochemical analysis methods and saturated hydrocarbon gas chromatography–mass spectrometry. The distribution patterns, abundance, relative content, and ratios of different carbon compounds of tricyclic terpane in hydrocarbon source rocks from fresh-to-mildly-saline (type I), moderately saline (type II), and saline (type III) water environments significantly differed. The C28–C29TT/C30H and C19–C29TT/C30H ratios were the lowest in the type I hydrocarbon source rock. The relative ratios of C23TT/C21TT, C25TT/C24TT, C28TT/C26TT, (C23–C26TT)/(C19–C22TT), and (C28–C29TT)/(C19–C22TT) gradually increased with the increase in the salinity of the hydrocarbon source rock. The percentage of low-carbon tricyclic terpanes gradually decreased to 28%, whereas those of the medium- and high-carbon tricyclic terpanes increased to 52% and 20%, respectively. The differences in triterpane types of different hydrocarbon source rocks were mainly controlled by the depositional environment. The primary factor that controlled the distribution pattern; relative abundance, especially the high carbon tricyclic terpane content; and differences in the relative ratio of different carbon compounds in different hydrocarbon source rocks was the salinity of the ancient waterbody during deposition.

Upper Jurassic Source Rock Evaluation and Thermal Maturity Evolution of the NW Sab’Atayn Basin, Yemen

Of Yemen’s Mesozoic basins, the Sab’atayn Basin offers the most significant potential for oil and gas exploration. The key consideration in the evaluation of source rocks to hydrocarbon exploration is the quantity and nature of the organic materials in sedimentations. Using organic geochemistry and total organic carbon content, organic-rich sediments from the Meem (Lower) and Lam (Upper) members from four wells in the NW Sab’atayn Basin were evaluated. The information gained reveals that the Meem source rocks have a total organic carbon content (TOC) value between 0.2–1.68 wt%, therefore suggests fair to very good source rocks. Only two samples in the Kamaran-01 well had values greater than 3 wt%, compared to the Lam source rocks’ values, which range from 0.2 to 3.81 wt%, which suggest excellent source rocks. The majority of the samples are made up of reworked organic debris, with no possibility for interesting source rocks, according to the Rock-Eval pyrolysis data. The majority of the Meem and Lam source rocks samples under study have Tmax values below 440 °C, placing them in the immature to marginally mature and on the main periphery of main phases of hydrocarbon formation. Based on the results of the Meem source rocks’ generative potential (GP), it may be inferred that non-generative rocks status of Meem source rocks due to GP values less than 2 mg HC/gm rock. Additionally, if the burial depth is sufficient to generate the necessary temperature and pressure, source rocks with extraordinarily high GP values of more than 10 mg Hc/g rock may serve as an efficient source rock for the Dahamr Ali-01 well. On the other hand Lam source rock is classified as moderate source rocks. Non-generative potential has been reported from Lam source rock in Himyar-01 well where the GP is less than 1 mg HC/g rock. The cross-plots of pyrolysis characteristics, such as HI versus Tmax (modified van Krevelen diagram) and TOC vs S2, which are most likely the result of deposition of more terrigenous type III organic materials derived from terrestrial in the study area, can be used to determine the kerogen type for Lam and Meem source units. The analysis of Meem source rocks demonstrated that they are typically plotted in the mature zone; however samples of Lam source rocks proved that they have been still immature, merely marginally mature in the Dahamr Ali-01 and Saba-01 wells.

Experimental data on organic matter maturation investigation in one sample of the Bazhenov shale formations (Western Siberia)

The paper presents the results of the closed system hydrous pyrolysis isothermal kinetic experiment on a source rock sample from the Bazhenov shale formation. After 48 hours of thermal exposure at a temperature of 350 °С 80% of the kerogen generation potential relative to the original sample was transformed into hydrocarbons. Organic matter changes during laboratory modeling of maturation, controlled by pyrolytic parameters, follow the same trends as in natural source rocks. The kinetic spectra of kerogen activation energy destruction show a heterogeneity of organic matter inside the rock. At the constant frequency factor, a decrease in low-energy bonds and an increase in the release of hydrocarbon compounds from 53 to 54 kcal/mol are observed. Calculated changes in hydrocarbon compounds formation at different activation energies depending on maturity level are different from experimental ones, which indicates the influence of maceral composition and necessity to take into account a variability of individual components in basin modeling.

Study of Hydrocarbon Potentials and Sedimentary Properties of Ispartaçay Formation, Turkey

The idea of the current work was the combination of the organic geochemical analyses, and the study of sedimentology characteristics of the source rock samples collected from the Ispartaçay Formation (Cretaceous period) between the city of Antalya and the city of Isparta, southwestern Turkey. Total Organic Carbon analysis and Rock-Eval pyrolysis were performed on the 24 samples taken from the study area, in order to evaluate quantitatively, and qualitatively organic matter and thermal maturity to determine the potential for hydrocarbon production. As well as studying the petrographic features (component and diagenesis), microfacies analysis, and sedimentary environment of the Ispartaçay Formation. The successions of the Ispartaçay Formation are poor to fair organic matter content and consist of dark grayish limestone, marly limestone, shale, massive cherty limestone, and thin-bedded radiolarian limestone. Total Organic Carbon values indicate that Ispartaçay Formation rocks are fair potential. Besides this, most of the samples from the Ispartaçay Formation contain mature to pot-mature (Type III -Type IV) kerogen. Petrographically, the particle portion of the Ispartaçay sediments is composed mainly of radiolarians, and planktonic foraminifera, In addition to the presence of a proportion of benthic foraminifera, whereas the groundmass is composed of micrite. Generally, the present sediments are subjected to some diagenetic processes like silicification, cementation, and dissolution. The microfacies analysis revealed that the succession of the Ispartaçay Formation is composed of alternations of two major microfacies, namely lime mudstone and lime wackestone microfacies. Depending on the facies and petrographic evidence, Ispartaçay Formation represents sediments deposited in the mid to outer ramp environment.

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.

1D basin modeling and hydrocarbon generation potential of the Late Carboniferous Limburg Group formations, Northwest European Basin, Netherlands

The Carboniferous rock samples of the Limburg Group formations were studied to investigate the source rock characteristics and the hydrocarbon generative potential. The source rock samples have been collected representing four rock units from three different wells. These samples were analyzed using Rock-Eval pyrolysis results and measured vitrinite reflectance values, and also by generating a one-dimensional basin model of K1 Field. The total organic carbon in these samples varies from 0.31 to 83.56% with a mean of 37.68%, suggesting that Limburg Group formations have excellent potential as a source of hydrocarbons. Kerogen in the Limburg Group formations is type II-III and type III, generate gas prominently. The outcomes of thermal maturation by Tmax and measured vitrinite reflectance reveal that the examined Limburg source rocks are located in the mature zone. The burial and thermal history models show irregular trend patterns due to uplift, erosion, and non-deposition events that took place in the K1 field (where the structural element is Cleaver Bank High). For the Maurits Formation, the oil generation took place at 2011 m at 230.1Ma ago and the top of the gas window was encountered 217.8Ma ago at 2535 m, whereas for the Hospital Ground Formation, the top of the oil window was encountered 186.8Ma ago at 2404 m and the gas generation took place at 2404 m at 161.9Ma ago.

Petroleum geochemistry and origin of shallow-buried saline lacustrine oils in the slope zone of the Mahu sag, Junggar Basin, NW China

Recently, significant oil discoveries have been made in the shallower pay zones of the Jurassic Badaowan Formation (J1b) in the Mahu Sag, Junggar Basin, Northwest China. However, little work has been done on the geochemical characteristics and origins of the oil in the J1b reservoir. This study analyzes 44 oil and 14 source rock samples from the area in order to reveal their organic geochemical characteristics and the origins of the oils. The J1b oils are characterized by a low Pr/Ph ratio and high β-carotene and gammacerane indices, which indicate that they were mainly generated from source rocks deposited in a hypersaline environment. The oils are also extremely enhanced in C29 regular steranes, possibly derived from halophilic algae. Oil-source correlation shows that the oils were derived from the Lower Permian Fengcheng Formation (P1f) source rocks, which were deposited in a strongly stratified and highly saline water column with a predominance of algal/bacterial input in the organic matter. The source rocks of the Middle Permian lower-Wuerhe Formation (P2w), which were deposited in fresh to slightly saline water conditions with a greater input of terrigenous organic matter, make only a minor contribution to the J1b oils. The reconstruction of the oil accumulation process shows that the J1b oil reservoir may have been twice charged during Late Jurassic–Early Cretaceous and the Paleogene–Neogene, respectively. A large amount volume of hydrocarbons generated in the P1f source rock and leaked from T1b oil reservoirs migrated along faults connecting source beds and shallow-buried secondary faults into Jurassic traps, resulting in large-scale accumulations in J1b. These results are crucial for understanding the petroleum system of the Mahu Sag and will provide valuable guidance for petroleum exploration in the shallower formations in the slope area of the sag.

Impact of natural weathering on source rocks: ESI FT-ICR MS evidence from Triassic Chang 7 outcrop profile in Tongchuan City, Southern Ordos Basin (China)

Atmospheric, water, and biological interactions with source rocks exposed at or near the surface due to tectonic uplift can result in both the loss of quantity and variability in the chemical composition of organic matter (OM) in source rocks during natural weathering, especially in extractable organic matter (EOM). Most of the research work on weathering has focused on characterization of the changes of saturated and aromatic hydrocarbon fractions in EOM at molecular level. However, few studies have reported how weathering affects polar compounds in EOM. In this work, a series of source rock samples with varying degrees of weathering were obtained from the Yishicun Profile of Triassic Chang 7 member in Tongchuan City of the Ordos Basin, providing an opportunity to study the weathering mechanisms of EOM in weathered source rocks. Gas chromatography-mass (GC-MS) and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) were used to analyze the chemical composition and variations in the characteristics of EOM. Asphaltenes, resin fractions, and the slightly oxygenated heteroatomic species (O1–O3) identified by positive- and negative-ion ESI showed a clearly pronounced enrichment trend during weathering due to the oxidation of saturated and aromatic hydrocarbons (biodegradation and photo-oxidation). While saturated, aromatic fractions and the highly oxygenated heteroatomic species (O5–O6) showed a declining trend. Additionally, it was also observed that the highly oxygenated heteroatomic species with low carbon number (CN) showed a more significant loss trend than their high CN counterparts during weathering. This may be due to depletion by surface water leaching due to the high water solubility of these compounds. Therefore, both the oxidation and surface water leaching can play important roles in regulating the OM chemical composition of source rocks during natural weathering.

Comparison between Rock-Eval® and temperature-programmed pyrolysis/mass spectrometry for the analysis of environmental and geological samples

Natural organic matter (OM) has a complex structure whose complete structural and chemical description remains a challenge. Rock-Eval® device constitutes a rapid and affordable method for obtaining key quantitative and qualitative parameters on OM. Previous studies on soil samples proposed to deconvolute or to split into temperature slices Rock-Eval® S2 pyrograms in order to distinguish and quantify chemical fractions of increasing thermal lability. In order to provide support for such an assumption, this work proposes a methodological approach based on coupling a temperature-programmed pyrolyser to a standard mass spectrometer (Py-MS). In this manuscript, we compare results acquired by Rock-Eval® pyrolysis with those from Total Ion Current (TIC) traces obtained by Py-MS on a set of reference soil samples, completed by dissolved OM, source rock and coal samples, in order to test the extent to which this approach can be generalized. Our results show good quantitative and qualitative agreements between the two methods. This comparison is a prerequisite before going further and addressing the molecular significance of S2 pyrograms deconvolution through the examination of m/z fragments abundance curves.

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.

Identification and Characteristics of Source Rocks in Lt-1 Well, Northern Kenya

This study on the hydrocarbon source rocks identification of LT-1 well in a Tertiary rift basin, northern Kenya, which had oil and gas shows was based on the organic matter quantity, quality, and the thermal maturation generation capability of the organic matter disseminated in the analysed rock samples. The organic matter contents were determined directly from laboratory analyses of the source rock samples with the help of seismic and gamma-ray profiles, total organic carbon (TOC wt%), maturity indices (HI and PI), temperature maximum (Tmax °C), porosities and other sedimentological parameters. This study involved a series of analytical geochemistry and petro-physical studies in ascertaining a number of effective source rock samples from the well cores which were then analysed in terms of TOC, PI, HI, S2, S1 and Tmax to determine oil/gas prone samples (resource areas) and distinguish them from strata with very high organic matter content. The samples with very high TOC were identified for possible source rock characterisations of the lithology pertaining to the well in terms of potential source-reservoir-seals associations. The Rock-Eval pyrolysis data were useful in assessing and evaluating the type of organic matter, thermal maturity, and the generation capability of source rocks for hydrocarbon exploration rationale. The analyses revealed that some strata within the sampled well data have high hydrocarbon generation potential with the existence of commercial hydrocarbon production. In conclusion, after an in-depth comparison and study of organic carbon content, hydrogen and production indices, type of organic matter content and maturity of organic matter, we confirmed that the studied resource areas are favourably considered for medium- to large-size hydrocarbon discoveries.

Geochemistry of an unconventional, saline lacustrine petroleum system: Dongpu depression, Bohai Bay Basin, China

Inter-salt shales are both important organic-rich sediments and shale oil exploration targets. This paper examines the controls on the composition of retained fluids in an inter-salt lacustrine shale oil system based on geochemical analysis of 125 samples with vitrinite reflectances of approximately 0.9% Ro from a 50 m shale-rich sequence between two evaporites. Core samples were immediately stored at −50 °C to reduce the evaporative loss of hydrocarbons. The sequence is highly heterogeneous and includes siltstone, argillaceous mudstone, calcareous mudstone, dolomitic mudstone, and argillaceous dolomite. Source rock samples with higher TOC contents (>1.0 wt%) and higher genetic potentials (S1 + S2 > 2.0 mg HC/g rock) are typically calcareous mudstone, dolomitic mudstone, and argillaceous dolomite, and contain predominantly type II kerogen. Salinity controlled both bottom water deoxygenation and the development of carbonate minerals, and the increase in aquatic organisms (including prokaryotes and eukaryotes) leads to a positive relationship between OM richness and quality. High TOC (>2.0 wt%) samples contain oil-prone kerogens and have high absolute contents of liquid hydrocarbons (S1-1 > 0.2 mg HC/g rock, S1-2 > 1.0 mg HC/g rock), and high relative contents of liquid hydrocarbons [(S1-1 + S1-2)/(S1-1 + S1-2 + S2-1) > 0.45]. The amount of oil retained in source rock horizons is mainly controlled by the sorptive properties of the solid phase organic matter. Oils (S1) within siltstones are derived from adjacent source intervals; multi-stage temperature pyrolysis shows that they are lighter – and thus more readily produced - than the oils retained within the source intervals. Although the absolute amounts of oil in siltstones are lower than those in the source intervals, a smaller fraction is sorbed on solid phase organic matter, so that there are similar amounts of moveable oil in siltstones and source rocks. Interbedded siltstones, organic-rich calcareous mudstones, dolomitic mudstones, and argillaceous dolomites are all favourable intervals for inter-salt shale oil development.