Organic Geochemical Parameters Research Articles

Comprehensive evaluation of the organic-rich saline lacustrine shale in the Lucaogou Formation, Jimusar sag, Junggar Basin, NW China

To explore a comprehensive evaluation method for saline lacustrine shale, samples were collected from the shale strata of the Lucaogou Formation in the Jimusar Sag, Junggar Basin. Organic geochemical and mineralogical parameters were assessed through TOC evaluation, rock pyrolysis, and XRD. Quantitative analysis of pore structure was achieved using a combined low-pressure N2 adsorption and mercury intrusion. Optical microscopy and FE-SEM analyzed macerals and pore morphology, respectively, while 2D NMR identified varied hydrogen-containing components in the shale. The findings revealed predominance of inorganic pores in saline lacustrine shale strata, with a lower occurrence of organic pores. The saline lacustrine sediments were in the late stage of oil generation. The siltstone and type III3 carbonate felsic shale displayed an abundance of type II1 organic matter, low vitrinite and inertinite contents, high macroporous volumes and surface areas, and they possessed a high content and fluidity of free oil, despite being lower maturity (0.85%<Ro<1.1%), making them attractive for shale oil exploration. Finally, we propose a comprehensive evaluation method for saline lacustrine shale strata considering free oil content (26% contribution), pore structure (23% contribution), maturity (16% contribution), macerals (13% contribution), free oil mobility (12% contribution), and organic matter type (10% contribution), encompassing various lithofacies.

Pore systems and their correlation with oil enrichment in various lithofacies of saline lacustrine shale strata

The potential of China's saline lacustrine shale oil resources is enormous. Currently, the storage space of saline lacustrine shale oil remains unclear, posing significant challenges for commercial development. In this study, we selected the samples from the typical saline lacustrine shale strata of the Lucaogou Formation, Jimusar Sag, Junggar Basin and investigated the pore systems and their relationship with oil content S1 of different lithofacies. The pore structures were quantified by using the combination of low-pressure N2 adsorption and mercury intrusion. TOC assessment, rock pyrolysis, and XRD were utilized for characterizing the organic geochemical and mineralogical parameters. The results showed that the organic matter comprising type III mainly appears in the clay-enriched lithofacies (types I2, II1 and III2), while the organic matter types I, II1 and II2 can be found in other lithofacies. Regarding the nine lithofacies, siltstone has the highest oil content S1, followed by the felsic-enriched lithofacies (types III3 and III1). The enrichment of oil in siltstone, carbonate rocks, and felsic-enriched lithofacies (types III3 and III1) is primarily attributed to macropores. Conversely, in clay-enriched lithofacies (types I2, II1 and III2), the oil content S1 is attributed to both the mesopore fractal dimensions (D1 and D2) and the TOC content. Moreover, the higher the complexity of the mesoporous structure (D2) and the larger the macropore surface area in clayey carbonate felsic shale (II3), the greater the oil content S1. It is further observed that, macropores with size range between approximately 60 nm and 3000 nm are abundant in siltstone and felsic mineral-enriched lithofacies (i.e., carbonate felsic shale III3 and felsic shale III1). Furthermore, the siltstone shows the widest oil-rich macropore size range (range of 70–1000 nm), followed by felsic shale (III1) (range of 150–1000) and carbonate felsic shale (III3) (range of 100–110 nm). Siltstones and felsic-enriched shales are optimal for exploiting saline lacustrine shale deposits.

Organic Geochemical Evaluation of the Black Shale interbeds Within the Lithological Succession of the Al Aziziyah Formation, NW Libya

The samples under investigation represent the black shale in interbeds within the Al Aziziyah Formation, located in the NW part of Libya and were analysed using geochemical techniques method and a variety of organic geochemical parameters. The aim of this study is to assess the type of organic matter, thermal maturity, and environment of deposition, based on biomarker distributions and Rock-Eval pyrolysis. The Gas chromatograms of the saturated hydrocarbon fractions of the study samples display a smooth high-end member distribution of the n- n-alkanes extending beyond nC34. The sample displayed evidence of biodegradation as suggested by the presence of the loss of some of the lower molecular weight n-alkanes. The predominance of high molecular weight n-alkane in the study sample suggests a significant input of higher land plant organic matter into these sediments. Geochemical (Rock-Eval, Tmax. values ranging from 416-4390C typical of immature range). Another related feature of these rocks extracted is the presence of a high relative abundance of gammacerane, indicating an anoxic marine hypersaline source depositional environment. The relatively high abundance of common land-plant-derived biomarkers, such as oleananes, is a clear indication of major terrigenous input to the source of these extractable organic matters. The high abundance of C24 tetracyclic terpanes could be associated with higher land-plant, algae, or microbial sources, thereby suggesting a mixed source input. TOC valued &lt; 0.5 wt.%, in the analyzed samples can be considered as a poor source rock generative potential. Based on this study, it can be said that the interbedded shales of the Al Aziziyah Formation seem to have received substantial amounts of land-derived organic matter that has been transported into an open marine subtidal depositional setting had prevailed and was deposited in a photosynthetic-organisms dominated environment (thereby suggesting a mixed source input).

Organic facies and hydrocarbon source rock potentiality of the Neogene succession in the Central South Mediterranean, offshore Nile Delta Basin, Egypt

Neogene succession in the offshore Nile Delta region is essential to the hydrocarbon petroleum system. Up to date, little is known about the nature and distribution of organic matter and its potential to generate hydrocarbon. This potential is tested through extensive palynofacies and organic geochemical analyses in a new approach in this region. Based on the palynofacies analysis, the samples from NDOB-1 and Baltim-1wells are discriminated into four types using the statistical application of cluster and principal component analyses. These four types are distal-High Oxic type A, proximal-suboxic type B, proximal-dysoxic type C, and distal-oxic type D. In addition, the analysis leads to identifying the proximal-distal and oxygen depletion trends based on the values of the principal component analysis (axis 1). This palynofacies analysis is used as an environmental framework for hydrocarbon source rock evaluation. This evaluation is integrated with the organic geochemical parameters by pyrolysis (Rock-Eval and gas chromatography) and spectroscopic (Fourier Transform Infrared) methods. This study reveals that the dominant kerogen types are IV (inert) and III (gas-prone) which are remarked by the opaque and brown translucent phytoclasts palynofacies types A and D, respectively. Kerogen type II is presented in a minor abundance in palynofacies types B and C that are distinguished with AOM. However, kerogen type II organic matter is much diluted with kerogen type IV and III, leading to poor to fair organic geochemical quality (S2 and hydrogen index). Both wells' maturity levels are detected within the Kafr El Shiekh Formation. Nevertheless, the poor hydrocarbon source rock quality becomes important if considered with the volume and thickness of the Neogene sediment, as indicated by the source potential index that has a cumulative value of 2.5 t HC/m2 in NDOB-1 well and 2.8 t HC/m2in Baltim-1 well. These values are comparable to some of the prolific hydrocarbon fields in other places.

An FR–IR model method for restoring the original organic geochemical parameters of high over-mature source rocks with types I and II kerogen in China

Deep natural gas source rocks are generally in a stage of high over-maturity. Based on the TOC and hydrocarbon generation potential (HGP) data, the accuracy of present evaluations of deep oil and gas resource potential are greatly reduced. The original TOC and HGP determine the quanlity of hydrocarbon generation from organic matter (OM), therefore, it is particularly important to restore the original organic geochemical parameters. By determining the HI and Tmax of numerous source rocks ranging in maturity levels from immature to over mature, it was found that the HGP characteristics of marine and continental source rocks with the same OM type were similar, providing a prerequisite for the establishment of forward recovery (FR) and inversion recovery (IR) models. Based on the relationship between the TOC and HI of immature to low-maturity source rocks with types I and II kerogen, the original HI was corrected, and the original TOC thresholds for different OM types of source rocks were determined to optimize the FR–IR model. Through the thermal simulation experiments of many samples, the TOC conversion rates from the immature to over mature stages were obtained, and the FR model was formed. The IR model was established based on geochemical data of the organic source rocks of types I, II1 and II2 with different maturity levels. Finally, by considering the typical marine and continental high over-mature source rocks of the world, the restoration results of the FR and IR models were found to have good correlation (average of 0.96) and coincidence rates (average of 72.2%). It was proven that the established FR–IR model have universal applicability in the restoration of the original TOC and HGP of marine and continental high over-mature source rocks with types I and II kerogen, especially in China.

Discussion on Transitional Shale Gas Accumulation Conditions from the Perspective of Source-Reservoir-Caprock Controlling Hydrocarbon: Examples from Permian Shanxi Formation and Taiyuan Formation in the Eastern Margin of Ordos Basin, NW China

Transitional shale gas, rich in resources, is expected to be a practical contributor to the increase in shale gas reserves and production in China. Its exploration prospect has been demonstrated by several wells in the Daning-Jixian block on the eastern margin of the Ordos Basin. In this paper, the Lower Permian Shanxi Formation (P1s) and Taiyuan Formation (P1t) in the eastern margin of Ordos Basin were compared for organic geochemical parameters, revealing that the overflow fan + lagoon combination (OLC) of the third sub-member of the second member of Shanxi Formation (P1s23) and the marine + lagoon combination (MLC) of the first member of Taiyuan Formation (P1t1) are the most favorable shale gas intervals. The two intervals were comparatively analyzed with respect to mineral composition, brittleness, caprocks, and preservation conditions. It is found that the OLC of P1s23 has a similar porosity to and much lower permeability than the MLC of P1t1 (or MLC1) and a BET surface area of 10–15 m2/g, which is smaller than the MLC1 (15–20 m2/g). Moreover, OLC has a brittle mineral content equivalent to MLC1 but a brittleness index of 33.73–62.36 (avg. 49.86), smaller than MLC1 (53.34–58.27, or avg. 55.85). OLC contains sandstones at both the roof and floor, with a higher permeability than shale in the interval, which cannot serve as good physical seals. In contrast, MLC1 contains limestones with lower permeability at the roof and floor, which, together with the overlying coal seams, have hydrocarbon generation capacity and can physically seal the MLC1 shale but also fill it with hydrocarbons, making MLC1 have higher gas content and superior for shale gas exploration than the OLC shale. Due to the multi-lithologies developed in transitional facies, besides the organic matter enrichment, and reservoir characteristics, it is necessary to find a suitable lithological combination to ensure the gas in shale can be better preserved and retained.

Microstructures of continental organic-rich shale and its adjacent siltstone and carbonate rocks—An example from the Lucaogou Formation, Jimusar Sag, Junggar Basin, NW China

To investigate pore structure of a continental shale and its adjacent carbonate rock and siltstone, 93 shales, 30 carbonate rocks and 10 siltstone samples from the Lucaogou Formation, Junggar Basin were examined by using low-pressure gas (N2 and CO2) adsorption, mercury intrusion and FE-SEM. Total organic carbon (TOC) evaluation, Rock-Eval pyrolysis, and X-ray diffraction (XRD) were used to characterize the organic geochemical parameters and mineralogical parameters of studied samples. The results showed that the free hydrocarbon S1 decreased in the order of siltstone, shale and carbonate rock, which is in accordance with the macropore surface area results. The carbonate rock has the highest TOC content and pyrolytic hydrocarbon S2, followed by shale and siltstone. The inter-crystalline pores of clays and intergranular pores exist widely in shale and siltstone, and a large number of dissolution pores were developed within shale, carbonate rock and siltstone. The smectite, illite and illite/smectite together control the micropores and mesopores of shale, more macropores and mesopores are present in the low TOC shale, carbonate rock and siltstone, however, the promotion effect of TOC on micropores of carbonate rock is stronger than clay. The more macropores of shale and siltstone, causes higher amounts free hydrocarbon S1. In addition, the free hydrocarbon S1 is higher at low fractal dimension D1 (D1＜2.3) and high fractal dimension D2 (D2＞2.6) of mesopore in shale. The free hydrocarbon S1 of the massive siltstone and thin layered shale are significantly higher than that of other types, which may be related to that high macropore volume and low mesopore fractal dimension D1 of the thin layered shale and the high macropore surface area of massive siltstone.

Prediction of vitrinite reflectance of shale oil reservoirs using nuclear magnetic resonance and conventional log data

With the change of oil and gas exploration and development focus to shale reservoirs, the source rock has become a research hotspot in well logging. It is of great significance to obtain continuous organic geochemical parameters based on log data. In this paper, according to the density-bulk model of hydrocarbon source rocks, a new indicator parameter named UTM, which can characterize the thermal maturity, is constructed based on the variation of kerogen density with thermal maturity in the Jimusar Sag of Junggar Basin. This parameter can characterize the thermal maturity and be calculated by density log, nuclear magnetic resonance (NMR) log and total organic carbon content of core. This parameter has the advantage of avoiding the difficulty of calculating kerogen density. The model was validated using cores and log data that were not involved in the modeling. The vitrinite reflectance predicted by the UTM index was in good agreement with the actual cores demonstrating the reliability and applicability of the method. The method provides a new idea and practical solution for the quantitative characterization of thermal maturity in the shale oil fields.

Organic geochemistry and petrography of Miocene ombrotrophic coals in the tropical Asem-Asem Basin (Kalimantan, Indonesia): Comparison to coeval subtropical coals in the Eastern Alps

Abstract The middle Miocene Warukin Formation in the Asem-Asem Basin (Kalimantan) contains a 20-m-thick coal seam (BL1) that is mined at the Jumbang mine. The seam, formed in a tropical peat, was studied to reconstruct the peat-forming environment and to compare its characteristics with those of similarly aged tropical coals from the Tutupan mine in the Barito Basin (Kalimantan) and similarly aged (~15 Ma) subtropical coal from the Leoben Basin in the Eastern Alps (Austria). Although all coals were formed in ombrotrophic peatlands, the comparison reveals differences in biomarker and maceral composition due to the different climate and flora. The study is based on 22 coal and three non–coal samples, each representing a stratigraphic interval of 0.2 to 1.0 m. The samples were analyzed for ash yield, carbon and sulphur contents, and maceral composition. Organic geochemical parameters were obtained on eight coal samples to obtain information on the peat-forming vegetation. The low-ash, low-sulphur BL1 seam was deposited in an ombrotrophic basinal (coastal) mire. Locally increased sulphur contents in the lower coal bench BL1L demonstrate brackish influence and a near-shore environment. The vegetation was dominated by angiosperms including abundant dammar resin producing Dipterocarpaceae, while the contribution of gymnosperms was negligible. The Tutupan seams T110 and T210, which were formed in kerapah (inland) ombrotrophic mires, have similar ash yields and sulphur contents but contain higher, although still low, concentrations of gymnosperm-derived diterpenoids. In addition, lower amounts of cadinane-type biomarkers and resinite suggest that Dipterocarpaceae were less dominant in kerapah peats. While differences between tropical coals from Kalimantan are minor, major differences exist between the tropical coals and the subtropical ombrotrophic Leoben coal. These include significantly higher concentrations of gymnosperm-derived biomarkers in subtropical peat, lower amounts of resinite due to the absence of Dipterocarpaceae, as wells as lower amounts of leaf- and rootlet-derived macerals. Apparently, fungal activity was also reduced in the sub-tropical Leoben peat. Surprisingly, the average amount of oxidized plant remains is also lower in the subtropical peat.

GEOCHEMICAL CHARACTERISTICS OF CRUDE OILS FROM THE SHARARA‐C OIL FIELD, MURZUQ BASIN, SOUTHWESTERN LIBYA

Crude oil samples from the Sharara‐C oil field (Concession NC‐115, Murzuq Basin, SW Libya) were analysed by organic geochemical methods in order to infer the geochemical characteristics of their respective source rocks. Aromatic hydrocarbons were analysed by gas chromatography – mass spectrometry (GC‐MS), and gas chromatography – tandem mass spectrometry (GC‐MS‐MS) was used to analyse saturated biomarkers. The Sharara‐C oils are interpreted to have been generated by marine shales containing mixed terrigenous and marine organic materials deposited in an intermediate (suboxic) environment. Age‐specific biomarker ratios indicated that the oils are older than Cretaceous, and maturation‐related parameters pointed to their high thermal maturity. Consistent with previous studies, source rocks are inferred to be “hot” shales in the Lower Silurian Tanezzuft Formation.Almost all the parameter ratios calculated varied over a very narrow range, indicating that the investigated oils were compositionally similar. The only significant difference that was noted concerned the sterane/hopane ratios whose variation suggested that there was some variability in the composition of the source organic material.The organic geochemical parameters determined for the Sharara‐C crude oils were compared with published data on other crude oils from Concession NC‐115. Almost all the parameters agreed well with previously published data on oils from this part of the Murzuq Basin. The greatest deviation concerned the values of some of the maturity parameters. This tended to confirm the conclusions of previous studies concerning the presence of a number of distinct oil families and sub‐families in the Sharara oil field area which are genetically related but which have different maturities.

Impact of natural weathering on source rocks: Organic and inorganic geochemical evidence from the Triassic Chang 7 outcrop profile in Tongchuan of the Southern Ordos Basin (China)

Exposure of buried source rocks at or near the surface causes organic matter (OM) to be subjected to loss through weathering impacts. A detailed organic and inorganic investigation of the natural weathering of the Triassic Chang 7 Yishicun Profile in Tongchuan City of the Ordos Basin revealed pronounced changes in bulk, molecular, mineral, and elemental compositions. In this study, systematic and visible variations caused by natural weathering were shown in the amount and composition of both organic (kerogen and extractable organic matter [EOM]) and inorganic matter (minerals and elements). The results indicate that natural weathering could substantially affect the characteristics of source rocks at a depth of 2 m from the surface, resulting in a 41% decrease in total organic carbon (TOC) and a 75% loss of EOM. Furthermore, changes were noted in kerogen elemental compositions, fractional compositions of EOM, and some geochemical parameters from Rock-Eval pyrolysis. The mineral and major, trace, and rare earth element (REE) compositions of the outcrop samples were also analysed and compared. The weathering of source rocks was mainly due to the influence of surface water leaching and biodegradation of the OM. This resulted in the oxidation of kerogen and the preferential depletion of low-carbon-number n-alkanes and low-molecular-weight high-water-solubility biomarkers. This has led to bias in petroleum geochemical interpretation based on these organic geochemical parameters. The major elemental composition indicated that the outcrop profile was moderately weathered. Moreover, some commonly used palaeoenvironmental geochemical proxies, including U/Th, AU, Mo, Sr/Ba, Sr/Cu, and P/Ti, display varying degrees of weathering-related alteration. However, other palaeoenvironmental proxies such as V/(V + Ni), Ni/Co, V/Cr, δU, and Ceanom experienced little variation and remained reliable for environmental interpretation. Thus, petroleum resource evaluation and sedimentary environmental analysis of source rocks based on outcrop samples should consider the effects of natural weathering.

Coal deposition in the Barito Basin (Southeast Borneo): The Eocene Tanjung Formation compared to the Miocene Warukin Formation

Coal seams of Late Eocene (Tanjung Formation) and middle Miocene age (Warukin Formation) are present in the Barito Basin of Borneo. The seams are laterally continuous and can be traced over at least 20 km. The thickness of three Eocene seams in the TAJ Pit–1D mine ranges from 1.4 to 3.4 m. These seams (from base to top: D, C, B) were studied to reconstruct their peat–forming environment and to compare the characteristics of Eocene and Miocene coals. The comparison reveals differences in peat types, flora and climate. The study is based on 38 Eocene coal and six non–coal samples, each representing a stratigraphic interval of 0.2 m. The samples were analyzed for ash yield, carbon and sulphur contents, and maceral composition. Organic geochemical parameters (incl. biomarkers) were obtained on every second coal sample to obtain information on the peat-forming vegetation and its diagenetic alteration.The Eocene seams were deposited in rheotrophic mires with palm/fern–dominated vegetation. Transitions to local ombrotrophic mires cannot be excluded. Very low to low sulphur contents (max. 0.9 wt%) speak against a marine influence, despite a general coastal plain setting. Upward increasing sulphur contents in the lower seam D and the upper seam B are interpreted to reflect transgression, which ended peat accumulation. The seam C formed in a rheotrohpic seam with a relatively high water level. This favored the accumulation of aquatic plants.Miocene coals from the Warukin Formation in the Barito Basin were studied recently in a companion paper. The comparison of Eocene and Miocene coals shows major differences, which include: Miocene coals are significantly thicker (up to 50 m) and display a cyclic structure. Miocene coals accumulated in ombrotrophic mires dominated by more decay resistant angiosperm trees (and subordinate gymnosperms). Therefore, preserved plant tissues are more abundant in Miocene coals. In addition, Miocene coals contain a significantly higher amount of root–derived macerals (suberinite). Leaf–derived macerals (cutinite, fluorinite) and resinite are ubiquitous in Miocene coals, but even slightly more abundant in Eocene coals. At least part of the resinite in Miocene coals, but not in Eocene coals, is derived from dammar resin produced by Dipterocarpaceae. Fungal activity, recorded by high funginite percentages, was high in low-ash ombrotrophic and high-ash rheotrophic mires both in Eocene and Miocene times.

Geochemistry study of black shale in Barzewa and Warte Sections, Sargelu Formation, Kurdistan Region, Iraq

Sargelu Formation (Middle Jurassic) is characterized by a wide geographical distribution in Iraq and neighboring countries. This study includes two sections Barzewa and Warte locations in Erbil Governorate of Kurdistan region, Iraq, the organic, inorganic Geochemistry and mineralogical properties were recorded. Fifteen samples of Sargelu Formation black shales were gathered from both locations. The source rocks of the black shales have an intermediate to felsic composition. The illite crystallinity index (IC) of the studied black shale shows the high anchizone stage. The organic geochemical parameters were analyzed in Sargelu Formation, the black shale contains type II - III kerogen. The average total organic carbon (TOC) of black shale for both section is 4.29 wt.%. By using the ultrasound homogenizer process the C-H bond (hydrocarbon component) of black shale recovered from the solid state to the liquid state.

Laminar structure differences and heterogeneities in reservoirs in continental organic-rich shales: The Cretaceous Nenjiang Formation in the Songliao Basin

Shale has a unique laminar structure that is currently the focus of considerable interest and a great deal of research in the academic community and industry. Studies have focused primarily on the differences among laminar combinations, whereas only a few have investigated the structure of individual lamina. In this study, we use typical organic-rich shale from the Cretaceous Nenjiang Formation in the Songliao Basin as an example and analyze each individual lamina of the shale on a millimeter scale. We have investigated heterogeneities among the different laminae by using X-ray fluorescence analysis, rock slicing, laser scanning confocal microscopy, field emission scanning electron microscopy, total organic carbon (TOC), rock pyrolysis, X-ray diffraction mineral analysis, electronic computer tomography (nano-CT), nitrogen adsorption, and other experimental methods. Four laminar units — composed of clay minerals, feldspar-quartz, and calcite — are distinguished based on their different levels of Ca, K, and Fe. We designate these units as UA, UB, UC, and UD (from the top to bottom in the formation). The palaeoenvironment, organic geochemical parameters, and mineral compositions of the different laminar structures are “two-stage” in character. From UD to UA, TOC values indicate a slightly decreasing trend, whereas the calcite content indicates a substantial increase, which is related to gradual reduction in the paleodepth, increasing aridity of the climate, increase of salinity, and decrease of reducibility during the sedimentary period. Different laminae correspond to different pore structures. The pore types in units UC and UD are mainly clay mineral-related pores and pyrite intergranular pores. In contrast, calcite dissolution pores are common in units UA and UB. Nitrogen adsorption and nano-CT data indicate that the pore development degree and pore size of organic matter in units UC and UD are better than those of units UA and UB. The porosity of UD is 2.6 times higher than that of UA. Laminae have an important influence on shale quality. The traditional approach to shale evaluation takes laminar combinations in shale strata as the research unit. Switching the focus to the heterogeneity of individual lamina could help in the selection of “sweet spots” and identification of optimal locations for shale oil exploration and development.

Study on Organic Matter Enrichment and Reservoir Characteristics of Permian Longtan Formation Shale in Southeast Sichuan

The study of reservoir space development characteristics and the geochemical parameters of the Permian Longtan Formation in the southeast of the Sichuan Basin at Well X1 was analyzed by using core observations, optical thin-section observations, Ar-ion polishing, scanning electron microscopy, and nitrogen adsorption tests. Major and trace elements of samples, the V/Cr, U/T, enrichment coefficients EF (Mo) and EF (U), chemical alteration indexes CIA and Sr/Cu, and Mo, P, and other index values of different samples were calculated based on the test of organic geochemical parameters. The depositional environment of the Longtan Formation in the study area was systematically analyzed. The Longtan Formation was in a warm and humid climate during the deposition period. The main body of the sedimentary water was in an oxygen-depleted state, and a portion of it was in an oxidized state with high biological productivity. Therefore, it had a small deposition rate. The clay mineral content and organic matter content in the sample played a major role in controlling the development of reservoir space. The content of clay minerals in the sample was high, and it was mainly chlorite and a mixed layer of illite/smectite. Under a microscope, it was observed that the mixed layer of flake illite/smectite and chlorite aggregate mostly developed interlayer pores or microfractures, which played a positive role in the specific surface area and pore volume of the sample.

Sedimentary environment of the Upper Cretaceous Yogou Formation in Termit Basin and its significance for high-quality source rocks and Trans-Saharan Seaway

The Yogou Formation of the Upper Cretaceous is a potential source rock in the Termit Basin of Niger, and the TOC content of the upper member is 1.8–9 times that of the lower member. However, the influence of the sedimentary environment evolution on its organic matter heterogeneity is still unclear. In this paper, the evolution of the sedimentary environment of the Yogou Formation profile was studied from the aspects of micropaleontology, element geochemistry and biomarkers. A total of three third-order sequences (YSQ1, YSQ2 and YSQ3, from bottom to top) were identified in the Yogou Formation. The distribution of micropaleontology in different sequences indicates that YSQ1 mainly deposited in the marine environment, while, the YSQ2 and YSQ3 mainly deposited in the marine-continental transitional environment. The elemental geochemical analysis shows that the water salinity of YSQ1 was higher than that of YSQ2 and YSQ3. From YSQ1 to YSQ3, the terrestrial input increased, the climate became warmer and wetter, and the reducibility of water generally weakened. The biomarker characteristics and organic geochemical parameters indicate that the YSQ1 generally deposited in a sub-anoxic to anoxic environment, while the YSQ3 deposited in the environment frequently alternating from reduction to oxidation, and the reducing environment may provide a good preservation condition for the enrichment organic matters. The abundant terrigenous materials input and good preservation conditions may be the basic reason to form the mudstone with high TOC content in the upper member of the Yogou Formation. The same micropaleontological species found in the Termit Basin, Benue Trough and Bornu Basin provide evidence for the hypothesis that there was a trans-Saharan seaway between the Tethys Sea and the South Atlantic during the Cenomanian and Turonian transgressions. This study not only helps to clarify the enrichment and distribution regularity of high-quality source rocks in the Yogou Formation, but also provides some evidence for the existence of trans-Saharan seaway.

Unusual occurrence of alkylnaphthalene isomers in upper Eocene to Oligocene sediments from the western margin of Tasmania, Australia

The occurrence and distribution of alkylnaphthalenes in ten sediment samples from the upper Eocene–Oligocene in Site 1168 of Ocean Drilling Program Leg 189 in the western margin of Tasmania, Australia have been examined by gas chromatography–mass spectrometry. The samples are thermally immature and contain predominantly terrigenous organic matter. Concentrations of alkylnaphthalenes generally increase with burial depth. Peculiar isomer distributions occur in some samples near the Eocene–Oligocene boundary at 748–762 m, and in the deepest sample at 850 m. Three isomers, 1,3,6-trimethylnaphthalene (TMN), 1,3,6,7-tetramethylnaphthalene (TeMN), and 1,2,3,6,7-pentamethylnaphthalene (PMN), have abnormally high abundance relative to total alkylnaphthalenes. The relative abundance of 2,6- + 2,7-dimethylnaphthalene (DMN) is also higher than in other samples, whereas there is a low relative abundance of 1,6-DMN, 1,2,5-TMN, 1,2,5,6-TeMN, and 1,2,3,5,6-PMN in these samples. While 2,6- + 2,7-DMN, 1,3,6-TMN, 1,3,6,7-TeMN and 1,2,3,6,7-PMN are thermally more stable than 1,6-DMN, 1,2,5-TMN, 1,2,5,6-TeMN and 1,2,3,5,6-PMN, these isomers are unlikely to have been inherited from thermally mature strata, because other more thermally stable isomers such as 1,3,7-TMN, 1,3,5,7-TeMN and 1,2,3,5,7-PMN have not been enriched in a similar way in these immature samples. It is also unlikely that selective biodegradation of other alkylnaphthalene isomers resulted in relative concentration of 2,6- + 2,7-DMN, 1,3,6-TMN, 1,3,6,7-TeMN, and 1,2,3,6,7-PMN, as these compounds have not been demonstrated to have higher ability to resist biodegradation, and no consistent supportive evidence could be obtained from other organic geochemical parameters. Relative depletion of terrigenous-sourced 1,6-DMN, 1,2,5-TMN, 1,2,5,6-TeMN, and 1,2,3,5,6-PMN and algal-derived 2,3,6-TMN point to microorganisms as the most plausible precursors for the occurrence of these peculiar alkylnaphthalene isomers in the studied samples. 1,3,6-TMN, 1,3,6,7-TeMN and 1,2,3,6,7-PMN are structurally and genetically connected, and are considered to be the diagenetic products of drimane-type sesquiterpenes or hopanes from bacteria. More investigation of the diagenetic pathways of alkylnaphthalenes are required, because the identification of a microbial origin of alkylnaphthalene isomers may provide deep insights into the geochemical application of parameters based upon alkylnaphthalenes, such as thermal maturity parameters.

Changes in the Indian Summer Monsoon during the past 600 years: A high-resolution record from the Anshupa Lake, Upper Mahanadi Delta, Core Monsoon Zone of India

• Indian summer monsoon experienced alternate episodes of high and low rainfall. • The little ice age (LIA) was dominated by arid conditions. • Dominance of bacterial magnetism during LIA suggest low sedimentation rate . • Periodicities in χ lf reaffirm solar influence on Indian summer monsoon. The core monsoon zone (CMZ) is an ideal region for reconstructing the Indian summer monsoon rainfall (ISMR). Mineral magnetic and organic geochemical parameters have been measured for an AMS 14 C-dated sediment core from the Anshupa Lake, situated in the eastern part of the CMZ, to reconstruct changes in the paleo-monsoonal precipitation on a sub-decadal scale during the past 600 years. Based on the data obtained, two phases may be recognised in the sedimentation history of the lake over the past six centuries: Phase-I (1397 to 1850 CE) comprising sediments deposited during the Little Ice Age (LIA), and Phase-II (1850 CE to the Present) comprising sediments deposited after the LIA. The measured proxies show decadal to sub-decadal scale variations. The relatively low values of mineral magnetic parameters ( χ lf , χ hf , χ fd , SIRM, χ ARM / χ lf , χ ARM / S I R M , χ ARM / χ lf , and χ ARM / S I R M ) and more positive δ 13 C values during Phase-I suggest a weak ISMR compared to Phase-II. The variations in mineral magnetic parameters suggest that the ISMR was the lowest during the Spörer, Maunder and Dalton Minima, but strong during the intervening periods. This inference resonates with the δ 13 C and C/N profiles of the core. Bacterial magnetite is documented during the mid-16th to mid-17th century, suggesting warm and humid conditions in the intervening phase between the Spörer and Maunder Minima. The magnetic susceptibility ( χ lf ) data exhibit a number of periodicities similar to those shown by cosmogenic nuclide-derived Total Solar Irradiance (TSI) data, reaffirming a solar influence on the Indian summer monsoon in the core monsoon zone of India.

Source rock properties and kerogen decomposition kinetics of Eocene shales from petroliferous Barmer basin, western Rajasthan, India

Hydrocarbon exploration and production are going on in Barmer basin (Rajasthan, India) for more than a decade. The potential source rocks are of Paleocene – Eocene age, and Mesozoic siltstones form the reservoirs. The western and central portions of the Rajasthan basin are characterised by extensive lignite formations, which can be promising for artificial transformation to oil and gas. We study the source rock properties, depositional environments and hydrocarbon generation potential of the Paleogene lignitic shales of the Giral lignite mine and the Cretaceous Sarnu siltstones for their source and reservoir rock potentiality. The total organic carbon content (TOC) of the Giral samples range between 0.76 and 49.83 wt% and the thermal maturity, as reflected by the pyrolysis Tmax, lies between 412 and 468 °C. Sarnoo siltstones, on the other hand, have a very low TOC ranging from 0.02 to 0.08 wt% and a Tmax of 320–608 °C. The higher TOC and a lower oxygen index (OI) of Giral lignites and shaly lignites indicate the prevalence of a reducing depositional environment. Bulk organic geochemical parameters involving kerogen pyrolysis and thermal degradation kinetics indicate a more promising hydrocarbon generation potential in the lignite than shales, which, however exhibits higher thermal maturity of organic matter. Giral lignites as well as shales show dominantly Type-III heterogeneous kerogen, which is sourced from terrestrial organic matter. This is also corroborated by a broader distribution of activation energy derived from the thermal decomposition of the kerogen. The kerogen transformation ratio (KTR) and the hydrocarbon generation rate (HGR) suggest a considerably earlier and quicker kerogen transformation. Samples from the Sarnoo area offer no significant information on the source rock characteristics, due to their lean organic nature. However, lignites and shaly lignites of the Giral mine are identified as excellent candidates for their suitability towards easy conversion into hydrocarbon products through artificial techniques.

Characteristics of Hydrogen‐rich Coals in Southern China: Implications from Organic Geochemistry and Carbon Isotopic Compositions

AbstractThe organic geochemical characteristics of hydrogen‐rich coal in southern China were investigated synthetically through organic geochemistry and carbon isotope analyses. The results showed that the hydrogen contents of the test samples were more than 5.0% and the H/C atomic ratios were between 0.76–1.06. Samples were found to be composed mostly of Type II‐III kerogen, consistent with good hydrocarbon‐generation potential. The Ro (0.54–1.10%) and Tmax (430–453°C) values imply that the hydrogen‐rich coals were in low maturity to mature stages. Stable carbon isotopic ratios (δ13Corg) of the samples used varied from –24.5‰ to –23.4‰, the barkinite content ranging from 13.9% to 83.3%, indicating a predominantly terrestrial origin with marine influence during coal formation. Some organic geochemical parameters showed corresponding changes as the hydrogen content increased from 5.0% to 7.0%, however, the source inputs changed significantly when hydrogen content was greater than 6.0%. Terrestrial higher plants gradually become predominant within the coal‐forming materials, whereas this dominant position is not apparent at lower hydrogen contents, which is attributable to the strong seawater effect during the hydrogen‐rich coal formation process.