Source Rock Samples Research Articles

Comparison of source rocks from the Lower Silurian Longmaxi Formation in the Yangzi Platform and the Upper Devonian Semiluksk Formation in East European Platform

Due to the depletion of conventional hydrocarbon resources, both China and Russia are giving more attention to the exploration and production of unconventional oil and gas resources, especially those generated and accumulated within source rocks. In an attempt to further understand the mechanisms of these resources, detailed mineralogical, lithological, and geochemical studies were performed to compare source rock samples from i) the Longmaxi Formation of the Lower Silurian in the Sichuan Basin (China), and ii) the Semiluksk Formation of the Frasnian Stage of the Upper Devonian in the Volga-Ural region of the East European Platform (Russia). The results showed that the main mineral of the source rocks of both formations is chalcedony that formed during an outpouring of deep fluids onto the sea bed. Simultaneous thermal analyses of this mineral indicated similar thermophysical properties to those of the hydrothermal-sedimentary chalcedony from jasper. Moreover, a direct relationship between the chalcedony content and the total organic matter content in the samples from the two formations was established. The presence of biophilic chemical elements in the siliceous component of the source rock samples indicate that high total organic content values were likely due to the presence of biophilic chemical elements in deep fluids, which led to the large-scale development of biota and subsequent accumulation of organic matter during sedimentation. The findings also revealed that the organic matter in the source rocks of the two regions was at different stages of maturity. The organic matter in samples from the Volga-Ural region was less mature and only at the early stage of oil generation, whereas the organic matter in samples from the Sichuan Basin reached both oil and gas generation stages. The Longmaxi Formation is already in the shale gas exploration and development stage, and the Semiluksk Formation could also be regarded as an exploration target for shale oil reservoirs.

Linking source rock to expelled hydrocarbons using diamondoids: An integrated approach from the Northern Gulf of Mexico

Nanodiamonds (diamondoids) are the ideal geochemical tool for hydrocarbon-source correlation in high-maturity fields since they are thermally stable and outlast biomarkers (molecular fossils), which deteriorate with thermal maturity. Diamondoids form in the shallow subsurface as organic material reacts with clay minerals in source rock, thereby preserving information about the precursor organic compounds and parent minerals. The unique suites of diamondoids generated by these combinations allow direct linkage between expelled hydrocarbons and source rock facies. We compared diamondoid distributions obtained from oils produced from both Eagle Ford Fm. and Austin Chalk Fm. in South-Central Texas, to rock extracts taken from equivalent intervals in a cored pilot hole. The targeted well is in the gas window where biomarkers are of limited use. Diamondoid distributions from oils produced from laterals in the Eagle Ford Fm. and the Austin Chalk Fm. matched extracts from those formations, proving that local sourcing is recognizable in expelled hydrocarbons.A second phase of this project included a direct comparison of results from pilot hole extracts to diamondoids analyzed from 15 oils selected from producing Eagle Ford wells. We showed a close match between the diamondoid chemistry of produced oils regionally and source samples from the Eagle Ford Formation in the cored pilot well. However, samples from immediately adjacent formations (Buda and Upson) were discordant, containing higher concentrations and different distributions of diamondoids when compared to the Austin and Eagle Ford systems.These results spurred a third phase of investigation that included generating diamondoid data from extracts of known Mesozoic Northern Gulf of Mexico (NGoM) source rocks stratigraphically beneath the Austin and Eagle Ford system. These included the Aptian-Albian Pearsall group and several Jurassic formations (Oxfordian Smackover Fm., Kimmeridgian Haynesville Fm., and Tithonian Bossier Fm.). The outlier samples from phases 1 and 2 are matched with deeper source rocks when comparing their diamondoid geochemistry to those of extracts from cored Jurassic source samples. These Jurassic intervals and migration pathways were then vetted with seismic data and integrated attribute analysis.The results of this work show: 1.expelled hydrocarbons can be linked to parent source rock using diamondoid composition; 2. diamondoids can be used to discriminate co-sourcing in intervals where routine biomarker analyses would fail; 3. Samples of well-known Mesozoic source rocks in the northern Gulf of Mexico (Cenomanian-Turonian Eagle Ford Fm., Tithonian Bossier Fm., Kimmeridgian Haynesville Fm., and Oxfordian Smackover Fm.) can be independently recognized using diamondoids, and 4. seismic anisotropy and fluid escape attributes helped delineate both deep-seated, through-going faults and intervals of high fracture density, allowing for connectivity and migration from the deeper source rocks illuminated by diamondoid analyses.

Oil origins, mixing and biodegradation in southwestern Junggar Basin, NW China

The southwestern Junggar Basin is an attractive region for oil exploration. A major discovery of high oil production rate from a recently drilled borehole stimulated a new round of extensive petroleum exploration in this region. The potential source beds are within the Permian, Triassic, Jurassic, Cretaceous and Paleogene strata, but no effective oil-prone source rock samples have been drilled so far due to deep burial, leading to that oil source correlation remains controversial in the region. A total of 38 crude oils and the free, adsorbed and inclusion oils obtained from 18 oil-containing reservoir rocks from the southwestern and southern Junggar Basin were analyzed by GC, GC–MS and GC–IRMS for the purpose to classify oil groups, determine oil origins, and identify effective source beds in sags. Crude oils in the southwestern Junggar Basin can be classified into two end groups and an intermediate group, namely PO, JO and PJO oils, which were originated from the Permian lacustrine source beds, Jurassic terrigenous source beds and both, respectively. Ratios of C19/C20 tricyclic terpanes and C24 tetracyclic/(C24 tetracyclic + C26 tricyclic) terpanes are the most sensitive parameters to distinguish these three groups of oils. These two ratios increase from PO, PJO to JO oils. JO oils can be further classified into two subgroups, i.e. J1O and J2O. J2O oils have substantially higher amounts of C27 and C28 steranes relative to C29 steranes, higher amount of gammacerane, lower amount of C29 diasteranes, and lower isomerization ratios of steranes, compared with J1O oils. J1O oils were exclusively originated from the Jurassic source beds while J2O oil were mainly originated from the Jurassic source beds mixed with minor oils generated from the Paleogene and Cretaceous lacustrine source beds. In the Chepaizi uplift, the major PO oils and extracted oils from 14 reservoir rocks were mainly originated from source beds within the Lower Wuerhe Formation of Middle Permian (P2w). However, the remaining minor oil samples and extracted oils from the other four reservoir rocks were clearly originated from source beds in the Fengcheng Formation of Lower Permian (P1f) on the basis of molecular parameters and δ13C values of individual n-alkanes, indicating the presence of effective oil-prone source beds within the Fengcheng Formation in the Shawan sag. In shallow reservoirs within the Neogene Shawan Formation (N1s), PO, PJO and J1O oils are severely biodegraded while J2O oils have nearly no biodegradation effect because the former entered the reservoirs much earlier than the latter.

The Sedimentary Evolution During Late Triassic‐Jurassic Period and the Hydrocarbon Exploration Direction in the Eastern Part of the Qiangtang Basin, Tibet

AbstractBased on the field outcrops surveyed, combined with recent published the regional tectonic evolution and geochronology data, we analyzed the lithologies and rock associations of strata, identified the sedimentary facies types, and discussed the distribution sedimentary facies and the hydrocarbon accumulation in the eastern Qiangtang basin during the Late Triassic – Jurassic. Marked by regional unconformities, there are two tectono‐stratigraphic units (from the Carnian to the Norian and from the Rhaetian to the Kimmeridgian, respectively) in the eastern part of Qiangtang basin. We systematically described the distribution range, thickness variation and lithological characteristics of different formations in the tectono‐stratigraphic units. The Late Triassic‐Jurassic is dominated by marine facies and marine ‐ continental transitional facies. The marine ‐ continental transitional facies include deltaic and tidal‐lagoon facies. Marine facies including gentle carbonate slope, evaporative platform, restricted platform, littoral, neritic, bathyal and abysmal facies. The Carnian stage is dominated by littoral–neritic–bathyal–abysmal facies in the north Qiangtang depression otherwise the littoral–neritic facies in the south Qiangtang depression. The early Norian stage is dominated by carbonate gentle slope‐mixed continental shelf facies. The late Norian, Bajocian, Callovian and Kimmeridgian stage are dominated by tidal flat‐delta facies in the north Qiangtang depression and littoral‐neritic facies in the south Qiangtang depression. The Bathonian and Oxfordian stage are dominated by evaporative platform‐ restricted platform‐ mixed continental shelf facies. The sedimentary facies formed zones from north to south and extended in an E–W direction. The Eastern Lower Uplift (ELU) played an important role in the division zones of sedimentary facies from north to south. During the Bathonian and Oxfordian, the ELU developed below the sea level and controlled the distribution of restricted platform, evaporative platform and platform margin. We analyzed 20 source rock samples from the upper Triassic‐Jurassic. The total organic carbon (TOC) value from Qoimaco, Buqu and Adula Formations. of late Triassic‐Jurassic in the eastern Qiangtang basin are ranges from 0.17∼0.33% (average 0.28%), 0.05∼0.25% (average 0.15%) and 10.32∼28.78% (average 19.33%), respectively. Obviously, the Adula Fm. developed good source rocks. The values of Tmax and S1+S2 in the Adula formation are 459–461°C (average 460°C) and 6.75‐28.55 mg/g (average 18.18mg/g), indicating that the Adula source rock has reached high‐over‐maturity stage. The bathyal, gentle slop and platform facie belts of the Upper Triassic can configurate the good hydrocarbon prospects in the northeastern area of the Qiangtang basin.

Origin of crude oils from the paleogene Xingouzui formation in the Jiangling depression of Jianghan basin, central China

The Paleogene Xingouzui Formation is one of the exploration targets in the Jiangling Depression from Jianghan Basin, Central China. However, the origin and source of crude oils remains controversial. In the present work, a total of 16 fresh source rocks and 23 oil samples were collected and geochemically investigated to clarify the source of organic matters, sedimentary environment and evolution degree. The Xingouzui Formation source rock samples are mainly of fair−good source rocks, with the TOC content, S1 and S2 of 0.36%–1.36% (mean of 0.74%), 0.14–0.38 (mean of 0.27 mg HC/g rock) and (mean of 1.12 mg HC/g rock), respectively. And these rocks are dominated by type Ⅱ2 kerogen within “oil window” maturity stage, with the Ro value of 0.6%–1.2% (mean of 0.9%). The biomarker results indicate that the source rocks of the Xingouzui Formation are mainly deposited in anoxic reducing environment, which main source materials are the mixture of terrestrial higher plants and lower marine organisms. The Pr/Ph values of the oils and source rocks range of 0.47–0.64 and 0.23–1.07, respectively. And the δ13C values of the oils and source rocks range from −34.93‰ to −26.41‰ and from −28.3‰ to −23.8‰, respectively. Family-I and family-Ⅱ oils were separated based on the results of biomarkers and stable carbon isotope, indicating that family-I oils, mainly occurring in the Wancheng fault zone and Gonggan slope zone, are characterized by relatively lower homohopane series, higher mature, and less input of terrestrial higher plants. Comparatively, family-Ⅱ oils mainly occur in the Jingzhou anticlinal zone, with the characterization of small amount of homohopane series, less mature and more terrigenous organic matter input. Family-I oils mainly originate from of the Ⅲ and Ⅱ groups of the lower Xingouzui Formation (Ex1-Ⅲ and Ex1-Ⅱ) source rocks in the Wancheng fault zone and less contribution from Ex1-Ⅱ source rocks of the Shiqiao monoclinal zone; while family-Ⅱ oils are mainly derived from the Ex1-Ⅲ source rocks in the north of Jingzhou anticlinal, and a small amount comes from the Ex1-Ⅱ source rocks of the Shiqiao monoclinal zone. In addition, Ex1-Ⅱ and Ex1-Ⅲ source rocks in the Wancheng fault zone show some contribution to family-Ⅱ2 oils. This work could provide scientific theoretical guidance for petroleum exploration and exploitation in the Jiangling depression.

Controls on organic matter enrichment in source rocks of the Shahejie Formation in the southwestern Bozhong Sag, Bohai Bay Basin, China

With the discovery of the Bozhong 19–6 large gas field in the Bohai Bay Basin, the study of lacustrine source rocks in the southwestern Bozhong Sag has garnered new interest. In this paper, 107 source rock samples of the Paleogene Shahejie Formation (Es) from the southwestern Bozhong Sag were analyzed with organic and inorganic methods and compared with other sags in the Bohai Bay Basin to reveal the depositional environment and controlling factors of organic matter enrichment during the deposition of the Es. The formation of source rocks (average total organic content = 2.76%) was subject to a combination of high organic productivity and enhanced organic preservation. Also, this was reflected by the existence of nutrient elements of P and Ba as well as other high productivity-related elements such as Cu, Zn, and Ni. The moderate Mo enrichment factor, Pr/Ph and low to moderate (C/P)org ratios were an essential part of this organic preservation. Moreover, the evidence we observed for the existence of hydrothermal activities consisted of high contents of quartz and pyrite, large positive Eu anomalies, and enrichment of elements related to hydrothermal fluids. Hydrothermal influence may lead to similarities and fluctuations in water salinity, organic productivity and preservation in the third (Es3) and first (Es1) members of the Es. Hydrothermal fluids may play an essential role in promoting the development of high organic productivity, stable reducing environment, and brackish water (as shown by the range of B/Ga and TS/TOC) in the lakes during the source rock deposition. This paper may provide implications for gas accumulation mechanisms and a complete set of organic and inorganic experimental data for source rock analysis in other lacustrine rift basins.

Organic geochemical characterization of crude oils and source rocks from Concession 6, central Sirt Basin, Libya

The Sirt Basin contains most of Libya’s producing oil fields and is in northern Libya, south of the Gulf of Sirt in the Mediterranean Sea. The main aims of this study were to characterize the type of organic matter and depositional conditions of the source rocks and thermal maturity of the crude oils in this region using a variety of geochemical techniques including gas chromatography (GC), gas chromatography/mass spectrometry (GCMS), stable carbon and hydrogen isotopes, total organic carbon (TOC), and Rock Eval analysis. Twelve crude oil samples from Cambrian–Ordovician Gargaf, Upper Paleocene Zaltan, and Middle Eocene Gialo reservoirs and seventy-nine source rock samples representing Sirt Shale samples from nine wells were collected from the Zaltan Platform and surrounding troughs in the central Sirt Basin. Organic geochemical parameters indicate that these oils were sourced from marine organic matter deposited under oxic to suboxic conditions. The oils were divided into three groups based on their whole oil carbon and hydrogen isotopic composition and thermal maturity as manifested by several saturate and aromatic hydrocarbon maturity parameters. Based on the geochemical data, it is proposed that there are at least two sources for the crude oils in the Zaltan Platform area of the central Sirt Basin. The study also indicates that the Sirt Shale source rocks from Maradah Trough are dominated by marine organic matter and have reached the main phase of oil generation.

Electromagnetic-heating enhancement of source rock permeability for high recovery

Source rock shales have permeability in the nano-Darcy range and require drilling long horizontal wells and extensive hydraulic fracturing to commercially produce hydrocarbons. Recently, an electromagnetic (EM) thermal method was proposed as a primary, or secondary, stimulation method to produce light hydrocarbons from extremely tight reservoirs. This method was based on the fact that EM heating rapidly elevates the pore-water pressure in tight rocks to fracture the reservoir. Since only the in-situ pore-water is needed, this is considered to be a water-free stimulation method, which is especially desirable for regions with limited water resources. Herein this further study provides an in-depth and quantitative investigation of the effects of laboratory EM stimulation on the permeability of the source rock shales under hydrostatic confinement and its dependence on the rock water content. In order to maintain hydrostatic pressure, a special pressure cell was built using nearly microwave transparent materials. Permeability of the samples before and after EM stimulation was acquired using a novel method capable of simultaneously measuring both matrix and fracture permeability. Microwave heating was found to generate extensive fractures in the source rock samples with a moderate amount of pore-water, which resulted in an increase of more than three orders of magnitude in permeability. This study provides further comprehensive evidence suggesting that EM thermal stimulation can be an efficient production method for source rock reservoirs and can result in both a high recovery rate and large estimated ultimate recovery of hydrocarbons.

Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea

The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.

Impact of marine incursions on lacustrine source rocks: organic matter quantity, quality, and kinetics in the Paleocene South Yellow Sea Basin, offshore eastern China

The impact of marine incursions during transgression, on the quantity and quality of organic matter in lacustrine source rocks, is critical to understanding their source rock properties and therefore on their hydrocarbon generation potential, but is also challenging and controversial. Here we examine this issue based on a case study in the South Yellow Sea Basin (SYSB) offshore eastern China, addressing organic matter (OM) quantity, quality and petroleum generation kinetics. A total of 139 lacustrine source rock samples was collected from the fourth member of the Paleocene Funing Formation (E1f4) in the SYSB, and investigated for organic petrographic and geochemical characteristics. The samples are immature to early oil window mature and the OM in all samples is dominated by terrigenous material, as shown by the organic petrography, relatively low hydrogen indices and biomarker distributions. The sediments are classified as inert to gas-prone. However, the presence of marine fossils (red and brown algae, coccolithophores and probably Neomonoceratinabullata) and the biomarker results, suggest that marine incursions occurred during the deposition of the lower unit of the E1f4 (E1f4L). The samples from this unit display higher HI values and more depleted δ13Corg ratios, but lower TOC and S1 + S2 contents, than the upper unit of the E1f4 (E1f4U) source rocks without marine influence. This suggests that marine incursions primarily improved the quality, rather than quantity, of organic matter. Bulk kinetics indicated that marine incursions also led to a more homogenous OM and compositional kinetics and phase properties suggest that black oil is generated throughout the process of kerogen conversion. Thus, our data suggest that marine incursions had a positive effect on the OM quality and oil generation potential of these lacustrine source rocks. Therefore, the impact of marine incursions should be fully considered during source rock evaluation of coastal lacustrine basins, especially during high sea-level stages. In addition, the greatest hydrocarbon exploration potential is observed in the South 4th Sag of the Southern Depression and thus this study provides valuable data for shaping regional exploration strategy in the SYSB.

Application of PCA and HCA in geochemical parameters to distinguish depositional paleoenvironments from source rocks

Oil-producing rocks can be characterized by organic, inorganic and palynological geochemical parameters to assess the quantity and quality of organic matter. In the present study, samples of source rocks collected from different formations (Fm) from the sedimentary basins of the Parnaíba (Pimentairas Formation) and Paraná (Irati and Ponta Grossa Formations) were evaluated through the geochemical correlation between the types of organic matter and their different depositional paleoenvironments using chemometric tools. Among the inorganic geochemical parameters used in this evaluation are the concentrations and the diagnostic ratios between the transition elements (Co, Ni, V, and Mo) and internal transition (lanthanides and U). The analysis of the transition and internal transition elements were performed by ICP OES (Ni and V) and ICP MS (Co, Mo, La, Ce, Pr, Nd, Sm, Eu, Gd, Tb, Dy, Ho, Tm, Yb, Lu, and U). The organic geochemical parameters selected for the characterization of the quantity and quality of the organic matter present in the samples of source rocks involved the determination of their total carbon content (%TOC) and sulfur (%TS), of the potential generator (S2) the amount of hydrocarbons produced by Rock-Eval pyrolysis and the calculation of the hydrogen (HI) and oxygen (OI) indexes. To compose the matrix of the multivariate analysis (PCA), were used ratios Ni/Co, V/Ni, U/Mo, V/V + Ni, TOC/TS the values of S2, HI, OI and the sum of rare earth elements (REE). The kerogen type, obtained through the HI and OI data, were also included in the matrix, information on the origin of the organic matter, and on the type of depositional paleoenvironment of each sample, obtained from previous works. It was observed the formation of three groups of data characterizing the formations Irati, Ponta Grossa and Pimenteiras according to the type of kerogen and organic matter, and also of its depositional paleoenvironment, showing that the exploratory data analysis allows the obtaining of rapid and efficient information on the chemical similarity between the complex samples from each formation.

Matrix permeability measurement from fractured unconventional source-rock samples: Method and application

Shale matrix permeability is one of the most important parameters for characterizing a source rock reservoir and for predicting hydrocarbon production. The low permeability value and the presence of induced fractures during core retrieval and transportation make the accurate measurement of the true permeability values for source rocks a significant challenge for the industry. The steady state flow method and the transient pressure pulse decay method on core plug samples mainly measure the permeability of fractures when fractures are present. While the Gas Research Institute (GRI) method that uses pressure decay on crushed rock samples was designed to overcome this difficulty associated with the induced fractures, its measurement results are reported to be sensitive to the particle size of crushed rock samples and also need correction of Knudsen diffusion effect. Moreover, the GRI method is limited to the unconfined stress condition.This work develops a practical method to measure the matrix permeability values from fractured source rock samples by extending the commonly used pressure pulse decay method. A source rock sample with fractures can be more accurately described by a dual-continuum system consisting of a fracture continuum and a matrix continuum. During the pulse decay test, the initial flow across the source rock sample is dominated by the fracture continuum because it has much higher permeability values than those for the rock matrix. Thus, the initial gas pressure signals from the test are used to estimate the fracture permeability. During the late-stage of a pulse decay test, the flow process within the rock sample is controlled by the rock matrix. The observed pressure signals at this stage are used for estimating matrix permeability. The method is based on the analytical solution to gas flow in the fractured rock sample and relatively simple to apply in practice. Both fracture and matrix permeability's dependence on the effective stress can be assessed with this method.

Biomarker distributions and depositional environments of continental source rocks in Sichuan Basin, SW China

In order to study the distributions of the biomarker of the continental source rocks in the Sichuan Basin, 71 source rock samples were collected from the Upper Triassic-Lower Jurassic strata in different regions. The n-alkanes, isoprenoids, terpane, sterane, sesquiterpenes, caranes and aromatics in the extracts were analyzed in detail. GC-MS analysis has been conducted to analyze the biomarker of the continental source rocks. The results of GC-MS analysis indicate that the Upper Triassic source rocks are high in the content of extended tricyclic terpanes, pristane, phytane, gammacerane, C28 regular sterane and carotene. However, they are low in content of rearranged compounds. The ratio of Pr/Ph is less than 1, with the characteristics of tricyclic terpane C21 > C23. The Lower Jurassic source rocks are extremely low in content (even zero) of extended tricyclic terpanes, pristane, phytane, gammacerane, C28 regular sterane and carotene, and high in content of rearranged compounds. The ratio of Pr/Ph is more than 1, with tricyclic terpane C21 > C23. These characteristics are still preserved after maturation. Moreover, during the sedimentation of the source rocks of T3x2–T3x3 members, the supply of continental plants was low (TAR < 1, with regular sterane C27 > C29, 1-MP/9-MP < 1). The source rocks of T3x5 member were low in salinity (slightly low content of gammacerane and carotene), being different significantly from the other Upper Triassic source rocks. In addition, during the sedimentation of the source rocks of J1dn Member, the supply of continental plants was also low (regular sterane C27 > C29, 1-MP/9-MP < 1), being quite different from that of J1l member. Through analysis of the difference in biomarkers, it is indicated that the sedimentary environment had changed from anoxic and brackish water during the Late Triassic to oxygen-rich and freshwater during the Early Jurassic in the Sichuan Basin. During this process, the types of organic matters had changed for several times.

Origin of hydrocarbon and non-hydrocarbon (H2S, CO2 and N2) components of natural gas accumulated in the Zechstein Main Dolomite (Ca2) strata in SW part of the Polish Permian Basin: stable isotope and hydrous pyrolysis studies

The genetic identification of natural gas accumulated in the Zechstein Main Dolomite (Ca2) strata in the SW part of the Polish Permian Basin (PPB) was determined by means of analytical and experimental methods of petroleum geochemistry including molecular and isotopic compositions, i.e. δ13C of C1–C5 hydrocarbon gases and CO2, δ2H of C1–C3 hydrocarbon gases and δ34S of H2S of natural gas and gases generated during hydrous pyrolysis (HP) experiments and δ15N of N2 of natural gas as well as results of geochemical analyses of organic matter of the Ca2 source rock samples including Rock-Eval (RE) pyrolysis and elemental and stable C isotope compositions of kerogen. Four HP experiments conducted on two composite samples from Ca2 strata with different (II and III) prevailing genetic type of kerogen each, led to production of thermogenic gas which was used for geochemical comparison with natural gases accumulated within Ca2 strata. Hydrocarbon gases of analysed accumulations belong to two different genetic groups: (i) including gases sourced from sapropelic organic matter (type II kerogen) dispersed in the Ca2 strata produced during either both microbial and thermogenic processes or solely thermogenic processes and (ii) comprising gases not genetically related to the Ca2 source rock, originated from humic organic matter (type III kerogen) of high maturity from deeper buried strata. CO2 related to Ca2 strata primarily was produced during thermal decarboxylation of kerogen and carbonate dissolution by acid fluids, while CO2 unrelated to Ca2 strata was generated from thermal decomposition of deeper buried carbonate formations. H2S has been generated during thermal decomposition of sulphur-containing organic matter and thermochemical sulphate reduction (TSR) processes. The coexistence of CO2 and H2S indicates that these components might have been produced together by TSR and less microbial sulphate reduction (MSR) processes. Molecular nitrogen in analysed natural gases was generated mainly during thermal decomposition of organic matter, but atmosphere-derived molecular nitrogen is presumably also present.

Stable carbon isotope evidence for the origin of C28 steranes in lacustrine source rocks from the Qikou Sag, Bohai Bay Basin, Eastern China

C27–C29 steranes are common constituents of crude oils and hydrocarbon source rocks and are usually dominated by either C27 or C29 compounds. In the current study, however, steranes dominated by C28 components were detected in eight lacustrine source rock samples in the first member of the Shahejie Formation in the Qikou Sag, Bohai Bay Basin of Eastern China. Ratios of C28/(C27 + C28 + C29) ααα 20R steranes in four samples can exceeded 50%. Furthermore, C27 triaromatic steroids, presumably originating from C28 steranes, were also observed at high levels, relative to C26 and C28 homologues. Stable carbon isotope compositions of a C28 ααα 20R sterane and C27 20R triaromatic steroid were found to be similar, with δ13C at −37‰ and −36‰ respectively, much lower than values for pristane (by ∼7‰) and total organic carbon (by ∼10‰). The abnormally low δ13C values of the steroids suggest that C28 ααα 20R sterane was biosynthesized by algae blooming in the water column during phases of overturn and mixing, such as in autumn, during which recycled CO2 and nutrients welling up from hypolimnion to the epilimnion are assimilated, contributing to a high algal productivity and low δ13C in algal organic matter.

The dead line for oil and gas and implication for fossil resource prediction

Abstract. Fossil fuel resources are invaluable to economic growth and social development. Understanding the formation and distribution of fossil fuel resources is critical for the search and exploration of them. Until now, the vertical distribution depth of fossil fuel resources has not been confirmed due to different understandings of their origins and the substantial variation in reservoir depths from basin to basin. Geological and geochemical data of 13 634 source rock samples from 1286 exploration wells in six representative petroliferous basins were examined to identify the maximum burial depth of active source rocks in each basin, which is referred to in this study as the active source rock depth limit (ASDL). Beyond the ASDL, source rocks no longer generate or expel hydrocarbons and become inactive. Therefore, the ASDL also sets the maximum depth for fossil fuel resources. The ASDLs of basins around the world are found to range from 3000 to 16 000 m, while the thermal maturities (Ro) of source rocks at the ASDLs are almost the same, with Ro ≈3.5±0.5 %. The Ro of 3.5 % can be regarded as a general criterion to identify ASDLs. High heat flow and more oil-prone kerogen are associated with shallow ASDLs. In addition, tectonic uplift of source rocks can significantly affect ASDLs; 21.6 billion tons of reserves in six representative basins in China and 52 926 documented oil and gas reservoirs in 1186 basins around the world are all located above ASDLs, demonstrating the universal presence of ASDLs in petroliferous basins and their control on the vertical distribution of fossil fuel resources. The data used in this study are deposited in the repository of the PANGAEA database at: https://doi.org/10.1594/PANGAEA.900865 (Pang et al., 2019).

Deep learning-based method for SEM image segmentation in mineral characterization, an example from Duvernay Shale samples in Western Canada Sedimentary Basin

Texture-based feature extraction and object segmentation are challenging in image processing. In this study, the U-Net architecture developed for biomedical image analysis was used to evaluate geologic characteristics depicted within scanning electron microscope (SEM) images of shale samples. With a revised weight function, the U-Net architecture allowed for effective discrimination of clay aggregates mixed with matrix mineral particles and organic matter (OM). In training, a local variability weight based on spatial statistics was used to enhance the contrast between features across boundary in the loss function of U-Net system optimization, thereby improving the ability of U-Net to distinguish the geologic features specific to our research needs. The Tensorflow neural network library was used to create semantic segmentation and feature extraction models in mineral identification. In the application example of the Devonian Duvernay shale study, we prepared 8000 randomly sliced image cuts (256 × 256 pixels) from four masked image tiles (6144 × 6144 pixels) with tagged feature objects, among which 6400 are for training and the remaining 1600 held image slices for validation. In the validation, the average of intersection over union (IOU) reaches 91.7%. The trained model approved by validation was used for clay aggregate segmentation and mineral classification. Three hundred SEM image tiles of source rock samples from different maturities in the Duvernay Formation were processed using the proposed workflow. The results show that the clay aggregates are clearly separated from other matrix mineral particles with acceptable boundaries, although both exhibit indistinguishable grey-level pixels. This approach demonstrates that texture-based deep learning feature extraction is feasible, cost-effective and timely, and can help geoscientists gain new insights by quantitatively analyzing specific geological characteristics and features.

Source rock characterization and oil-to-source rock correlation of a Cambrian -Ordovician fold-and-thrust belt petroleum system, western Newfoundland

Abstract In this study, we use biomarker and isotope data to address the complexities of petroleum system analysis in fold-thrust systems, specifically related to hydrocarbon generation and migration, such as variable thermal maturities of source rocks, complex migration pathways, and mixing. Source rocks, extracts, and oil samples are taken from Paleozoic rocks along the Appalachian structural front in western Newfoundland. Oil seeps along this fold-and-thrust belt have motivated episodic exploration efforts over the last 150 years. However, economic development has been unsuccessful to date, in part because of the complex nature of oil-to-source relationships. Pyrolysis analyses identify promising source intervals in Lower Ordovician (Floian) formations, with an excellent source potential containing type I/II organic matter (TOC up to 9.35%, HI up to 840). A second good source interval, identified within the late Cambrian (Furongian) continental slope and rise sediments, contains type II/III organic matter (TOC up to 2.34%, HI = 380). Source rock samples from outcrops are marginally mature to mature with Tmax values between 436 and 447. Geochemical analyses of source rock extract imply a clastic shale-dominated source rock with a minor contribution from carbonate source rocks. Chemometric analyses yield 3 extract groups. Groups 1 and 2 contain lower Ordovician samples with organic matter derived from oxidized micro-plankton with varying amounts of Gleocapsomorpha prisca. Extract group 3 originates from Cambrian samples and shows evidence of a bacterial-derived organic matter. Similar genetic relationships among 10 oil samples from natural oil seeps and abandoned well sites are indicated by high-resolution biomarker analyses. Seven oil samples originated from Ordovician source rocks that produced high API oils with low bisnorhopane/hopane, tricyclic/hopane ratios, and high sterane concentrations, supporting interpretation of a source containing algal-derived organic matter. Three oils originated from Cambrian shales. These high API oils show high bisnorhopane/hopane and tricyclic/hopane ratios, low sterane concentrations, and low carbon isotope values, all indicative of organic matter derived from bacteria, generated over a wide range of maturities (0.98–1.26 %Ro). Thermal maturity-sensitive biomarkers and naphthalene ratios show that source rocks generated oils with a wide range of maturities related to their dipping character in the imbricated thrust stack. The Cambrian source generated oils that locally experienced secondary cracking during Acadian inversion, whereas the Ordovician source generated oil with low maturities after the Acadian inversion. Oil operaters exploring fold-and-thrust belt petroleum systems may expect extreme changes of oil properties (for example, API gravity) in spacially restricted areas.

Organic facies and palynology from the middle to late Devonian of the Pimenteiras Formation, Parnaíba Basin, Brazil

A detailed study of organic facies and palynological assemblages was carried out on 11 samples of potential hydrocarbon source rocks of the Pimenteiras Formation, an outcropping at the western edge of the Parnaíba Basin, Brazil. The main objectives are to characterize the depositional paleoenvironment and hydrocarbon source potential. The selection of this outcrop occurred in the function of its preservation and accessibility, and the samples collection observed 1 m of vertical spacing. Generally, the organic matter and the palynomorphs showed a good state of preservation and fluorescence. The most notable spores and acritarchs and phycomates species were discussed in light of international biozones, and the chronostratigraphic range defined as Late Eifelian - Latest Frasnian in age. TOC results show ranges from 0.40 to 2.91%, with most samples showing greater than 1%, thereby holding a high potential generation. The S1 values were virtually null, and the S2 peak ranged from 0.9 to 5.33 mg/g. The kerogen 435 °C, and the ICE between 4.0 and 4.5 demonstrating the material immaturity. For the palynofacies associations definition, only 10 out of the 25 total quantified of subgroups of kerogen categories were considered in the counting of 300 particles. A dendrogram constructed based on these results through cluster analysis, revealed four palynofacies, as follows: I constituted mainly by palynomorphs (acritarchs, prasinophytes and sporomorphs); II – Dominance of Translucent organic matter (cuticles, epidermal tissue and translucent phytoclasts with and without structure); III - Dominance of Opaque/non-fluorescent (opaque phytoclasts and non-fluorescent AOM) and IV - Dominance of AOM fluorescent (amorphous organic matter with fluorescence). The palynomorphs are the most abundant constituents of all studied kerogen. Quantitative analysis based on the distribution of palynomorphs groups throughout the section indicates the dominance of sporomorphs in the palynological assemblages from the Middle Devonian aged samples. On the other hand, occurred the predominance of microplankton elements in the Late Devonian aged samples. Thus, the depositional paleoenvironment was established as a distal oxic mud-dominated shelf with the deltaic influence of the Late Eifelian to Late Givetian, and there is a tendency distal (dysoxic-anoxic ‘shelf’) from the Frasnian, which indicates the maximum flooding surface.

Maturity effects on steranes of source rocks in Lishu fault depression, Songliao Basin

Geochemical analysis results of 30 source rock samples from Lishu fault depression in Songliao Basin show that samples are compositionally similar and represent a uniform organic facies. Differential distribution of steranes among the samples is due to rank, with vitrinite reflectances (Ro) ranging from 0.65 to 1.61%. In the maturity stage (Ro = 0.65–1.20%), the absolute concentrations of steranes increase, which is affected by kerogen degradation, whereas the pyrolysis of high mature source (Ro = 1.20–1.61%) show a decrease in the abundance of steranes. Simultaneously, the parameters of steranes vary greatly with maturity. Decrease of prognane/regular sterane value with the increase of maturity suggests that pregnane is not a product of regular steranes pyrolysis. The ratios of C27/C29 regular sterane gradually increase, while the value of C29-20S/(20S + 20R) and αββ/(αββ + ααα) decrease at high maturity stage, which is associated with the difference in the thermostability of steranes involved. This reversed trend can be used to determine the high-maturity stage of source rocks. Whereas the values of rearranged steranes/regular steranes in source rocks show an apparent positive correlation with maturity, it, therefore, appears to be particularly useful for maturity assessment at elevated levels.