Kerogen Type Research Articles

Source Rock Evaluation and Hydrocarbon Generation Potential of the Cretaceous (Dokan and Gulneri) Formations in Bai Hassan-13 Well Section, Kurdistan, North of Iraq

Eleven cutting rock samples from both Dokan and Gulneri formations (Cretaceous) in one subsurface section of Bai Hassan-13 (BH-13) well in northern Iraq were studied by using two techniques for hydrocarbon generation potentiality. The geochemical technique included Rock-Eval Pyrolysis analysis, The optical technique was achieved by studying palynological slides. The rock-Eval pyrolysis results showed that Dokan Formation has total organic carbon (TOC) wt.% ranging between 1.16 % and 2.3 % (good to very good), Gulneri Formation has a high TOC of 1.34 % and 4.64 % (good to excellent) quantity of organic matter. About the quality of organic matter, both Dokan and Gulneri formations are composed of kerogen types I and II. The organic matter of the Dokan Formation is not indigenous (migrated), one sample of the Gulneri Formation is indigenous the other one is located on the slanted line separating the Indigenous from non-indigenous organic matter. The organic matter within the two formations are thermally immature source rock, Therefore, they cannot generate oil and gas. The palynological study revealed that amorphous organic matter is the predominant organic matter component in both formations with more than 89%, whereas phytoclasts and palynomorphs comprised only a few percentages. There is no great variation in the percentages of the mentioned organic matter components, except a slight increase in the percentage of phytoclasts and palynomorphs in the lower part of the Dokan Formation, therefore one primary palynofacies type can be recognized, and divided into two secondary palynofacies. Through plotting Tyson's Amorphous, phytoclasts, and palynomorphs (APP) diagram, it is clear that the two formations are deposited in a distal suboxic to anoxic basin.

Geochemical Parameters of Oil and Rock Samples from Murzuq Basin, Libya: An Application for Paleoenvironment Description

Seven sedimentary rocks and seven crude oils undertook a geochemical analysis to describe their organic matter type and then tag the Paleoenvironments based on the organic matter. The samples were collected from B1-NC151, A1-NC58, P1- NC1, E1-NC174, D1-NC151, H29-NC115, and D1-NC174 boreholes, located in Murzuq Basin. The study was established to understand life forms in the ecosystem based on biomarkers that biochemical techniques recognized. Microscopy was used for kerogen typing and Spore Color Index reference. Organic matter (EOM) was extracted from cutting samples. Furthermore, hydrocarbons were saturated and aromatic fractionated from the samples to investigate using Gas chromatograph system. Spore color index (SCI), range between 1.5-3.5, Amorphous organic matter (AOM) from 42 to 95 percentage, Phytoclasts % were 4-15.5, and Palynomorphs % range 0.5 to 7.5. The percentage of Carbon 85.66-86.29, Hydrogen 13.16-13.73, Nitrogen 0.06 -0.27, and Sulfur 0.31-0.70, besides wax were measured, ranging among 1.3 to 6.0 %. Pristine/n-C17, Phytane/n-C18, Pristine/Phytane, carbon preference index measurements (CPI) and DBT/P as saturated hydrocarbon ratios from whole oil chromatographs were established. Tricyclic terpanes, hopanes and n-alkanes were distinguishing as the most important oil biomarkers that reserved the characteristics in the Paleoenvironments.

Petroleum system analysis of Fujairah basin, eastern offshore of the United Arab Emirates

The Fujairah basin, located on the eastern margin of the United Arab Emirates, forms part of the hinterland basin of the Oman-UAE mountains. Despite its geological significance, the hydrocarbon potential of this basin remains unexplored. This study aims to address this knowledge gap by using 2D seismic reflection data, three exploration wells, geochemical data from one well, a 2D velocity section, and two pseudo-wells. The study began with the interpretation of the seismic profiles and then proceeded to create depth maps for the most significant units. We used Rock-Eval pyrolysis plots to identify the primary source rocks and to classify their kerogen types. The seismic interpretation formed a basis for the 1D and 2D basin modeling techniques that are used to determine the petroleum system of the basin. Our results identify the Pliocene, Miocene, and Eocene sequences as potential source rocks in the basin with TOC values less than 1 wt% and low expulsion efficiencies. The Pliocene and Miocene source rocks are mainly type-II kerogen, whereas most Eocene samples are characterized as type-III kerogen. The Pliocene and Miocene source rocks are immature in the basin. The Eocene is mature depending on the burial within the sub-basins. The Eocene started expelling hydrocarbons during the Burdigalian, which was linked to the collision of the Arabian and Central Iran plates along the Zagros suture zone. Structural and stratigraphic traps may have entrapped the generated hydrocarbons. The three drilled wells in the basin lack good reservoir rocks. However, low-velocity anomalies and bright spots indicate possible hydrocarbon accumulations in the basin.

Organic geochemical characterization and hydrocarbon generation modeling of Paleozoic-Paleogene shales, Wadi Sirhan basin, south-eastern Jordan

The Wadi Sirhan Basin in Jordan originated from the Arabian Platform and served as a stable shelf during the Paleozoic era. The Lower Paleozoic-Eocene sequence in the Wadi Sirhan Basin contains numerous shales, found, in ascending order the Upper Ordovician Dubeidib, Lower Silurian Mudawwara, Maastrichtian Ghareb, Paleocene Taqiyeh, and Eocene Sara fms. These strata warrant investigation of their source-rock potential and hydrocarbon generation modeling, to precisely elucidate the timing of petroleum generation. To achieve this, datasets were utilized from various analytical approaches, including Rock-Eval pyrolysis, visual kerogen analysis, pyrolysis-GC, and lipid biomarker geochemistry. The aim of this study is to assess these source rocks regarding organic matter quantity and quality, paleoenvironmental implications, thermal maturity, and petroleum generation depth/time. The Lower Paleozoic Dubeidib and Mudawwara shales are identified as effective source rocks, containing kerogen types II, II-III, and III. A high proportion of well-preserved, weakly fluorescent amorphous organic matter suggests an origin from marine plankton-derived alginite in an oxygen-deficient setting. These formations reached the peak oil window during the Devonian (∼405-380 Ma) and Carboniferous (∼320-300 Ma). The Dubeidib Fm experienced late-stage oil generation during the Early Triassic (∼255-250 Ma), with a transformation ratio (TR) of 68%. The Ghareb Fm predominantly contains type II kerogen, while the Taqiyeh and Sara fms mainly contain type I kerogen with minor type II kerogen. Thermal maturity assessments using integrated parameters indicate that the Dubeidib and Mudawwara shales have entered the main phase of hydrocarbon generation, while the Ghareb, Taqiyeh, and Sara shales remain immature. Furthermore, analysis of biomarker ratios reveals the dominance of marine over terrestrial organic matter in the studied strata. These clay-rich sediments were deposited under reducing conditions, which further facilitated the rearrangement of steranes into diasteranes. The modeled TRs indicate the generation and subsequent expulsion of hydrocarbons, but the absence of suitable reservoirs and/or improper trapping system, owing to the major Hercynian unconformity, led to an incomplete petroleum system in the basin. Additional investigation is required to evaluate the potential of the Early Paleozoic shales as subsurface unconventional resources, considering parameters such as brittleness index and hydraulic fracturing. This study holds important implications for future hydrocarbon exploration and development in the Wadi Sirhan Basin. The insights gained from such investigations could help mitigate the risk of petroleum exploration failures in the Wadi Sirhan Basin, guiding future exploration and development efforts towards promising approaches.

Characteristics and Origin of Natural Gas in Yongfeng Sub-Sag of Bogda Mountain Front Belt

By systematically analyzing the natural gas composition, carbon isotopes, and source rock characteristics in the Yongfeng sub-sag of the Bogda Mountain front belt, natural gas characteristics were determined, and the genetic types and sources of natural gas were investigated. The research results indicate that methane is the main component of natural gas in the Yongfeng sub-sag, with low levels of heavy hydrocarbons and a high drying coefficient. These characteristics make it dry gas, which refers to natural gas with a methane content of over 95%. The ethane carbon isotope δ13C2 of natural gas is −28.5‰ and belongs to oil type gas. The methane carbon isotope δ13C1 of natural gas is −58.6‰~−59.4‰, has a relatively depleted methane carbon isotope value, shows significant differences from the surrounding natural gas methane carbon isotope, and belongs to the category of biogenic gas. The Permian Lucaogou Formation is the main source rock in the study area, with good organic matter abundance. The microscopic components of kerogen are mainly composed of sapropelic formations and the organic matter type is I–II1. The source rock has a high maturity and has reached the mature stage, mainly consisting of oil and wet gas. The ethane carbon isotope of natural gas in the Yongfeng sub-sag shows as oil type gas, which is consistent with the kerogen type of the Lucaogou Formation source rocks, indicating that the natural gas mainly comes from the Lucaogou Formation source rocks. Based on comprehensive data and information on natural gas composition, carbon isotopes, and burial history of the source rocks, it is believed that some of the crude oil generated from the Lucaogou Formation in the early stage underwent biodegradation due to tectonic uplift, resulting in biogenic methane and the formation of crude oil biodegraded gas.

Organic matter enrichment model of fine-grained rocks in volcanic rift lacustrine basin: A case study of lower submember of second member of Lower Cretaceous Shahezi Formation in Lishu rift depression of Songliao Basin, NE China

Based on sedimentary characteristics of the fine-grained rocks of the lower submember of second member of the Lower Cretaceous Shahezi Formation (K1sh2L) in the Lishu rift depression, combined with methods of organic petrology, analysis of major and trace elements as well as biological marker compound, the enrichment conditions and enrichment model of organic matter in the fine-grained sedimentary rocks in volcanic rift lacustrine basin are investigated. The change of sedimentary paleoenvironment controls the vertical distribution of different lithofacies types in the K1sh2L and divides it into the upper and lower parts. The lower part contains massive siliceous mudstone with bioclast-bearing siliceous mudstone, whereas the upper part is mostly composed of laminated siliceous shale and laminated fine-grained mixed shale. The kerogen types of organic matter in the lower and upper parts are types II2–III and types I–II1, respectively. The organic carbon content in the upper part is higher than that in the lower part generally. The enrichment of organic matter in volcanic rift lacustrine basin is subjected to three favorable conditions. First, continuous enhancement of rifting is the direct factor increasing the paleo-water depth, and the rise of base level leads to the expansion of deep-water mudstone/shale deposition range. Second, relatively strong underwater volcanic eruption and rifting are simultaneous, and such event can provide a lot of nutrients for the lake basin, which is conducive to the bloom of algae, resulting in higher productivity of types I–II1 kerogen. Third, the relatively dry paleoclimate leads to a decrease in input of fresh water and terrestrial materials, including Type III kerogen from terrestrial higher plants, resulting in a water body with higher salinity and anoxic stratification, which is more favorable for preservation of organic matter. The organic matter enrichment model of fine-grained sedimentary rocks of volcanic rift lacustrine basin is established, which is of reference significance to the understanding of the organic matter enrichment mechanism of fine-grained sedimentary rocks of Shahezi Formation in Songliao Basin and even in the northeast China.

Hydrocarbon generation potential in Jurassic source rocks from hydrous pyrolysis experiments under ultradeep conditions

This study investigates the hydrocarbon generation potential of Jurassic source rocks under ultradeep conditions by utilizing semiclosed system hydrous pyrolysis experiments to simulate the geological processes at play. This study examines four distinct lithologies (shale, mudstone, carbonaceous mudstone, and coal) and three kerogen types (I, II, and III) across a temperature range of 250–650 °C and fluid pressures ranging from 34 to 100 MPa. The results indicate a bimodal distribution in total oil yields, with peak generation observed at approximately 350 °C and 600 °C. This pattern suggests a complex relationship between temperature, pressure, kerogen type, and hydrocarbon output. Notably, while I-Shale and II-Mudstone display higher hydrocarbon efficiency, III-type rocks exhibit superior oil and gas production rates because of their higher total organic carbon content. Research revealed that the oil expulsion rate exceeds 99% at temperatures above 500 °C, with the expelled oil predominantly comprising nonhydrocarbons and asphaltenes. Our findings suggest that Jurassic hydrocarbon source rocks maintain oil and gas potential under ultradeep conditions (high-over maturity stages at depths exceeding 6000 m). Under sustained fluid overpressure exceeding 70 MPa, the hydrocarbon generation peaks of various kerogen types in source rocks are markedly delayed. This phenomenon enables the source rocks to retain the potential for liquid hydrocarbon generation even during the stages of overmaturity. The results significantly enhance the theoretical framework of hydrocarbon generation under ultradeep conditions, thereby providing a crucial extension to the existing thermal boundary theory of hydrocarbon formation. These insights are crucial for the oil and gas industry, directing future exploration efforts towards ultradeep reservoirs and informing the development of new technologies to exploit these resources. This research not only enhances the understanding of subsurface hydrocarbon systems but also has implications for strategies aimed at maximizing resource recovery and managing the environmental impact of deep Earth exploration.

Geochemical characteristics of crude oils and source rocks in the Malaysia-Thailand Joint Development Area (MTJDA), North Malay Basin

The Malaysia-Thailand Joint Development Area (MTJDA) that located in the North Malay Basin has been investigated in this study to resolve few issues concerning to petroleum potential and resources which has been abandon for decades. Despite Malay Basin having been proven to contain prolific oil and gas resources, the MTJDA which located in the Northern area however contains mainly gas with very minor oil. Thus, this study aimed to investigate the main factor that controls the hydrocarbon generation, type and distribution in this basin. The investigation involves biomarker characterization, thermal maturity assessment of source rock, crude oil and condensate, together with oil-oil and oil-source correlation that has never been established before. The geochemical data as indicated by bitumen extraction, GC-MS and Py-GC analyses on 40 cutting samples and 8 liquid samples (six oil samples and two condensate samples) revealed that the cutting samples were moderate in quality with variable richness based on TOC (total organic carbon) and a variable degree of maturity based on the biomarker proxy parameters of isoprenoid, hopanoid and steroid. The organic matter input for the source rock was derived from a mixed marine-terrestrial and terrestrial source and deposited in fluvial-deltaic/estuarine settings having oxic to sub-oxic depositional conditions. Based on biomarker fingerprints and proxy parameters, the oil and condensate samples were essentially of the same group, originating from a similar source rock, with some facies variation due to variations in organic matter input and degree of maturity. The results also indicated that the crude oil samples were originated from the coaly and carbonaceous shales of Group I, with mixed kerogen of type II/III that could produce gas with minor oil. There is also the possibility that these hydrocarbons were generated from a deeper interval of Group E (higher thermal maturity), deposited in a similar setting as Group I.

Using benzonaphthothiophenes to trace paleo-oil migration directions in the Ediacaran-Cambrian reservoirs of the central Sichuan Basin

Benzonaphthothiophenes (BNTs) are important organosulfur compounds in oil, and their concentrations and [2,1]/([2,1] + [1,2])BNT ratio have been used as migration tracers. Here we focus on the applicability of BNTs as migration tracers for abnormally heat-altered paleo-oil reservoirs. For this purpose, 57 pyrobitumen samples from the Ediacaran to Cambrian dolomite reservoirs in the central Sichuan Basin were collected and detected by gas chromatography-mass spectrometry. The results showed that most pyrobitumens of the studied samples are characterized by high concentrations of unsubstituted polycyclic aromatic hydrocarbons (PAHs), high values of fluoranthene/PAHs, pyrene/PAHs, fluoranthene/(fluoranthene + pyrene), benzofluoranthene/(benzofluoranthene + benzopyrene), and unsubstituted-to-methylated aromatic ratios due to the alteration by abnormal heating. These pyrobitumens have high concentrations of BNTs, and their three isomers show a pattern of [2,1] > [1,2] > [2,3]BNT. The BNTs concentrations display a good positive relationship with the concentrations of the abnormal heating-related PAH, while [2,1]/([2,1] + [1,2])BNT ratio has no correlation with the abnormal heating-related indices, suggesting that abnormal heating of the paleo-oil reservoirs lead to the enrichment of BNTs but has a limited effect on [2,1]/([2,1] + [1,2])BNT ratio. Moreover, [2,1]/([2,1] + [1,2])BNT ratio seem to be not affected by kerogen type and depositional environment, but increases with source rock maturity. Therefore, the [2,1]/([2,1]+[1,2])BNT is still an effective migration tracer for abnormally heated reservoirs. This ratio was applied as migration tracer in the studied area. The result suggests that the paleo-oil primarily migrated from west depression to east bulges, followed by the direction from northwest to southeast, which is congruent with the geological setting and exploration practice, demonstrating the applicability of this parameter for abnormally heat-altered oil reservoirs.

Quantum physisorption behavior of methane in nanoporous shales: Model and new mechanism

Methane adsorption in nanoporous shales plays a significant role in the storage and flow of shale gas. Although previously numerous theoretical models have been proposed to describe the gas adsorption behavior, how the potential energy distribution in nanopores impacts gas adsorption remains unclear. The mechanism of methane adsorption in extremely complicated nanopores is still no satisfactory explanation. In this study, a total of 28 shale samples located in the Paleozoic-Mesozoic strata from different sedimentary environments were utilized to investigate the nature and process of quantum physisorption of methane in nanoporous shales. It was suggested that methane confined within nanoscale space shows a quantum effect, and the physisorption behavior of methane may be the result of molecular energy level transition. Further, the quantum physisorption model was developed by considering the quantum potential energy distribution, maximum adsorption amount, gas temperature and gas pressure, which matches the isothermal adsorption data well for a various of shales under widely varied temperature and gas pressure condition. The adsorption amounts of methane with different energy levels can also be obtained by the model. Finally, a new mechanism of the methane quantum physisorption in nanoporous shales was proposed. Uneven spatial distribution of gas molecules and elementary space of gas adsorption are the intrinsic factors of controlling the quantum physisorption behavior. The former is mainly influenced by minimum potential unit (E0) and gas temperature, while the latter is represented by the parameter of maximum adsorption amount (nL) which impacted by specific surface area and gas temperature. Gas pressure only affects the molecule concentration with different energy levels, but does not affect the spatial distribution of molecule. E0 and nL vary in shales from different sedimentary environments, due to the difference in organic matter properties (TOC content and kerogen type), which indirectly impacts the methane physisorption behavior. These results are helpful to deeply understand the storage of methane in shales and improve the efficient development of shale gas. In addition, this study is expected to open a new research direction about the quantum physisorption of gas in nanoporous media.

Neogene–Quaternary paleoenvironments and kerogen assessment of the NDO B-1 well, offshore Nile Delta, Egypt, Eastern Mediterranean: palynological evidence

Palynofacies and palynological investigations conducted on the Neogene–Quaternary succession from the NDO B-1 well, located in the offshore Nile Delta, Egypt, in the Eastern Mediterranean, suggest generally shallow marine (neritic) conditions. These environments are manifested by the overall palynofacies composition and the occurrence of dinoflagellate cysts (e.g., Spiniferites spp., Lingulodinium spp., Hystrichokolpoma spp., Homotryblium spp. and Selenopemphix spp.). Neritic environments are suggested for the lower and middle Miocene Sidi Salim, and the Pliocene to Pleistocene upper Kafr El Sheikh, El Wastani and Mit Ghamr formations, while shallower, coastal to inner neritic settings were interpreted for the late Miocene (Qawasim and Rosetta formations) and early Pliocene (Abu Madi and lower Kafr El Sheikh formations). Anoxic conditions existed during the deposition of the studied well succession, which can be seen from the occurrence of imprints of pyrite crystals and some types of oxygen-sensitive dinoflagellate cysts. The palynofacies fluctuated repeatedly between Amorphous Organic Matter (AOM)-dominated and phytoclast-dominated intervals, of kerogen types II and III, respectively. The spore coloration index (SCI) of indigenous thin-walled palynomorphs confirms thermally mature sediments, generative of dry gas and wet gas/condensates. Reworking during the deposition of the upper Sidi Salim, Qawasim and Rosetta formations is inferred from the occurrence of Cretaceous dinoflagellate cysts and pollen.

The unconventional petroleum system of a mixed siliciclastic-carbonate sequence: Irati Formation, Paraná Basin, Brazil

Widespread rhythmic intercalation of a millimeter- to meter-scale hydrocarbon source rock (organic-rich shale and marlstone) and a carbonate reservoir (micritic and peloidal dolostone) are unusual. Here, the case of the Irati Formation (Paraná Basin) is reported, in which source rock strata have high total organic carbon (averaging 10 to 20 wt%), with dominance of highly oil-prone kerogen type I and II. Multivariate statistical analyses were applied to find patterns in the geochemical multivariate data set. The data points to three main productive sectors in the basin: Paraná Sector, Santa Catarina Sector, and Rio Grande do Sul Sector. Quality, quantity, and petroleum potential vary both laterally and vertically. On the other hand, the reservoir carbonate beds are predominantly composed of low-primary pore space, in which the effective reservoir capacity is determined by the presence of postdepositional secondary porosity. In addition, the Paraná-Etendeka magmatism, which occurred during the break-up of the Atlantic Ocean, played an important role in thermal maturation and primary oil migration.

Shale Oil Generation Conditions and Exploration Prospects of the Cretaceous Nenjiang Formation in the Changling Depression, Songliao Basin, China

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part.

Enhancement of Biocrude Quality Using Fecal Sludge and Organic Solid Waste Through Two-Stage Hydrothermal Liquefaction Technique

The escalating global challenge of managing unmanaged fecal sludge (250-300 million tonnes/year) and organic solid waste (600-700 million tonnes/year) necessitates innovative and sustainable waste-to-energy solutions. Hydrothermal liquefaction (HTL) of FS & OSW to produce biocrude has been seen as a double-edged sword to substitute fossil fuel and address the issues relating to unmanaged waste (GHG emission, global warming, climate change). Through this study, an approach was taken to improve the biocrude production and enhance the biocrude quality by introducing a two-stage heating in HTL of FS and OSW separately. Four different runs were comprised in this study where one run was in conventional one stage, at 320℃ for 60 min. In terms of the other three runs, in the first stage, 100, 200, and 300℃ were retained for 30 min respectively and the second stage was conducted at 320℃ for 30 min. Results indicate a substantial improvement in biocrude yield of 15% &18% through two-stage heating during HTL (30 min at 200℃, and then 30 min at 320℃) compared to conventional single-stage HTL processes of FS & OSW respectively with a biomass conversion rate of 70%. From the analysis of biocrude maturity & intensity of oil we observe a high potential for crude oil formation being classified as Kerogen type I. GC-FID shows that increasing heat in the first stage tends to produce a lighter fraction (at 300℃ in the first stage produces biocrude with a lighter fraction>80% from FS & OSW feedstocks) in biocrude. In addition to improving the overall efficiency of converting organic waste to biocrude, the two-stage system offers a more flexible platform that allows the biofuel composition to be customized to match the needs of individual applications. The results show that a two-stage HTL process is a feasible and effective technique for converting difficult waste streams into biofuels, with implications for both environmental sustainability and energy security. Journal of Engineering Science 15(1), 2024, 95-105

Comparative organic geochemistry of shale deposits of northern Appalachian Basin

The organic-rich black shales in the Appalachian basin are a vital producer of natural gas. In this study, we present new multiproxy geochemical data from the Ordovician and Devonian black shales in New York (NY) and Pennsylvania (PA). The samples include outcrop samples collected in NY (Utica Group and Marcellus Formation) and core samples from PA (Marcellus Formation, Skaneateles Formation, and Genesee Group). We combined organic geochemical data (% total organic carbon or %TOC, δ13Corg, C/N ratio, and lipid n-alkane distribution) with trace element (TE) data to identify the organic matter (OM) sources and depositional conditions. The TE analysis data shows that water conditions were variable during the deposition of these black shales, fluctuating between oxic and dysoxic conditions with occasional anoxia. There was probably a change from an open water condition (Co∗Mn = 0.2) during the deposition of the Flat Creek Formation to a more restricted exchange later during the deposition of the Indian Castle Formation (Co∗Mn = 2.9) in the Ordovician. Basin circulation likely remained restricted during the deposition of the Devonian black shales (Co∗Mn ranges from 0.4 to 1.3). Based on δ13Corg values (−32.9‰ and −29.6‰) that are more depleted than marine OM δ13Corg, C/N ratios (11.2 and 9.2) higher than marine OM, and the presence of longer chain n-alkanes in the range of C25 to C33, we suggest that bryophytes were possibly a significant organic source to the Ordovician Utica Group in NY. The kerogen type in Utica Group samples is type III, mostly terrestrial OM. The Devonian NY and PA samples show mostly bimodal distributions. In some samples, a secondary, though sometimes dominant, shorter chain peak in the range of C14 to C20 is present, in addition to the long chain peak. We suggest the bimodal n-alkane distribution signifies a mixed OM source consisting of terrestrial and marine contributions with differing degrees of thermal maturation compared to the samples with a unimodal distribution. Our results suggest that samples from the NY Marcellus Group are composed of type III kerogen, while samples from the PA Marcellus Formation, Skaneateles Formation, and Genesee Group contain both type II and type III kerogens.

Petroleum source-rock characterization and the depositional environment of Kimmeridgian–Tithonian sequences, Jaisalmer Basin, western Rajasthan, India

In hydrocarbon exploration, total organic carbon (TOC) content and Rock-Eval pyrolysis are commonly employed geochemical techniques that offer concise insights into kerogen type, effective source-rock identification and thermal maturity. In the current study, the data obtained from Rock-Eval pyrolysis has been used to define the source-rock quality, generative potential, kerogen type, maturity of the source sediments and kerogen kinetics of the Baisakhi–Bhadesar Formation of Kimmeridgian–Tithonian (154.7–145.6 Ma) age. Basinal level hydrogen index (HI), TOC content, source-rock maturity, transformation ratio and heat-flow maps have been generated by integrating the data from pyrolysis with previously available data from wells drilled in the basin. The TOC content of the Kimmeridgian–Tithonian sequence ranges from 0.03 to 12.71% in the studied samples, with an average TOC content of 1.28%, indicating good source-rock quality. The HI, in collaboration with T max and vitrinite reflectance (VR o ) data, demonstrates that the Baisakhi–Bhadesar Formation is characterized by type II, a mixture of type II/III and type III kerogen facies and exhibits good source-rock quality and poor to good generative potential in the basin. The studied samples are marginally mature to mature in nature ( T max , 430–450°C; VR o , 0.52–0.72%). A maturity analysis of the basin suggests that during the Late Jurassic most areas were under the oil window zone, except for the Bhakhari Tibba and Miajlar areas. The transformation ratio overlay for the Kimmeridgian–Tithonian source sequences shows better transformations of the source rock in the area of the Shagarh Sub-basin. Kerogen kinetics of the studied Baisakhi–Bhadesar Formation demonstrate that the activation energy ranges between 46 and 74 kcal mol −1 with the significant distribution of activation energy being 54 kcal mol −1 (42.07%), representing a strong heterogeneous type of organic matter in the sediments. Based on lithological, palaeontological and electrolog studies, a shallow-marine to nearshore environment of deposition with a sediment-input direction from the SE has been inferred for the Kimmeridgian–Tithonian sequences. The results of this study quantitatively establish the role of the Kimmeridgian–Tithonian sequence as a source rock, ultimately contributing to the generation of hydrocarbons in the basin along with spatial changes in the quality of source sediments in different parts of the basin.

Source Rock Assessment of the Permian to Jurassic Strata in the Northern Highlands, Northwestern Jordan: Insights from Organic Geochemistry and 1D Basin Modeling

The present study focused on the Permian to Jurassic sequence in the Northern Highlands area, NW Jordan. The Permian to Jurassic sequence in this area is thick and deeply buried, consisting mainly of carbonate intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC, wt%), Rock-Eval pyrolysis, visual kerogen examination, gross composition, lipid biomarkers, vitrinite reflectance (VRo%), and bottom-hole temperature measurements. The main aim was to investigate the source rock characteristics of these strata regarding organic richness, kerogen type, depositional setting, thermal maturity, and hydrocarbon generation timing. The Permian strata are poor to fair source rocks, primarily containing kerogen type (KT) III. They are immature in the AJ-1 well and over-mature in the NH-2 well. The Upper Triassic strata are poor source rocks in the NH-1 well and fair to marginally good source rocks in the NH-2 well, containing highly mature terrestrial KT III. These strata are immature to early mature in the AJ-1 well and at the peak oil window stage in the NH-2 well. The Jurassic strata are poor source rocks, dominated by KT III and KT II-III. They are immature to early mature in the AJ-1 well and have reached the oil window in the NH-2 well. Biomarker-related ratios indicate that the Upper Triassic oils and Jurassic samples are source rocks that received mainly terrestrial organic input accumulated in shallow marine environments under highly reducing conditions. These strata are composed mostly of clay-rich lithologies with evidence of deposition in hypersaline and/or stratified water columns. 1D basin models revealed that the Upper Triassic strata reached the peak oil window from the Early Cretaceous (~80 Ma) to the present day in the NH-1 well and from ~130 Ma (Early Cretaceous) to ~90 Ma (Late Cretaceous) in the NH-2 well, with the late stage of hydrocarbon generation continuing from ~90 Ma to the present time. The present-day transformation ratio equals 77% in the Upper Triassic source rocks, suggesting that these rocks have expelled substantial volumes of hydrocarbons in the NH-2 well. To achieve future successful hydrocarbon discoveries in NW Jordan, accurate seismic studies and further geochemical analyses are recommended to precisely define the migration pathways.

Depositional environments and thermal maturity of the hydrocarbon source rocks in the Devonian–Early carboniferous Ora Formation from palynological organic petrographic investigations in northern and western Iraq

The study investigates the palynofacies, organic matter character, and hydrocarbon generation potential of this rock unit, based on surface and subsurface samples from the Ora Formation type-section in extreme northern Iraq and the Akkas-3 well in western Iraq, respectively. Dark, mostly oxidized, gelified platy amorphous organic matter (AOM) dominates the palynological components in the surface section, in addition to a few rounded spores and structured phytoclasts. In contrast, palynomorphs, including Ambitisporites avitus, Aneurospora spp., Vallatisporites verrucosus, Acinosporites spp., Verrucosisporites nitidus and the algae Botryococcus, are predominant in studied samples from the Akkas-3 well. Statistical cluster analysis identified three palynofacies types in the surface section based on stratigraphic variations in the particulate organic matter. These vary from high amorphous organic matter (AOM), moderate phytoclast, and low palynomorph abundances that represent proximal suboxic–anoxic shelfal environments to moderate to good AOM and low to moderate palynomorph abundances that represent distal suboxic–anoxic or distal dysoxic–anoxic shelfal environments. The organic petrographic study of the outcrop section also revealed the strong effect of oxidation, where dispersed terrigenous and amorphous organic materials in the form of granular and gelified forms dominate and reflect a terrestrial origin of these components. In the subsurface section, a mixed terrestrial and less marine or lacustrine origin characterized the studied organic matter, where land plant spores (sporinite), in addition to vitrinite and inertinite, are dominant with a few scattered liptinite macerals. The difference in thermal maturity between the outcrop and subsurface samples is likely due to the higher tectonic burial of the outcrop samples that form part of the Northern Thrust Zone of Iraq. Nevertheless, higher abundances of AOM (oil-prone kerogen type II) accumulated in the northern outcrop type section. This might imply that the Ora Formation has a higher potential for hydrocarbon production north of the Akkas field.

Facies distribution, paleoenvironment and hydrocarbon potential of Kanawa Member of Pindiga Formation, Gongola Basin, Northern Benue Trough, Nigeria

The Gongola sub-basin is a frontier inland sedimentary basin consisting of Cretaceous to Tertiary sediments, believed to have been deposited in continental to coastal shallow marine complex. The Kanawa Member of Pindiga Formation is a sequence of limestone and shale. Sedimentology, facies analysis, biostratigraphy, thermal maturity assessment and kerogen typing were conducted on these strata to determine the facies, facies associations, facies successions, paleoenvironment, age, and hydrocarbon generation potential. The studied sequences are of Turonian–Santonian age, deposited due to a major transgression of the basal part of the Pindiga Formation. The shale-limestone series of the Kanawa Member is interpreted as lagoon-to-shallow marine deposits of a carbonate ramp depositional system. The sediments consist of mainly wackestone and packstone facies and shallow marine foraminiferal, suggesting that the Kanawa Member was deposited under low-energy condition. The presence of Ammobaculites subcretacea, Haplophragmoides bauchensis, Haplophragmoides pindigensis, Haplophragmoides excavata, Ammobaulites pindigensis, Ammobaculites bauchensis, Ammobaculites gombensis, Ammobaculites benuensis Ammoastuta nigeriana, Reophax guineana and Miliammina pindigensis foraminiferal assemblages, indicating Late Cretaceous age. Hydrocarbon potential is interpreted to be gas prone although, minor oil could be expected. These correspond to temperature range (TAI values) of 60 to 75 indicating thermally matured for both oil and gas generation.

When an explosion of life leads to death – hypoxic zones in the Menilite Shales from the Silesian Unit (Polish Outer Carpathians)

Oligocene siliciclastics belonging to the Silesian Unit in the Outer Carpathians were sampled from five locations (Iwonicz Zdrój, Krosno, Równe, Rymanów Zdrój, Zmysłówka) with the first four locations connected to Menilite Shales. The sample from Zmysłówka is an example of the lowermost part of the Krosno Beds. Preliminary geochemical results obtained from the Rock-Eval analysis suggested the presence of immature mixed II/III Type kerogen. Detailed geochemical (GC-MS) and petrological analyses show evidence of extensive phytoplankton blooms, causing the occurrence of episodic ferruginous hypoxic zones. Hypoxic zones were present in the photic zone, where molecular evidence of green and/or brown pigmented sulfur reducing bacteria were marked. The size and character of the blooms were controlled by the palaeoenvironmental conditions. In cases of intense nutrient-rich freshwater loading by a palaeoestuary and/or rainfall, extensive algal blooms were reported. With the increasing aridity and/or decrease of the palaeoestuary impact, the phytoplankton blooms gradually acquired a mostly bacterial character and were reduced in size. The most hypoxic conditions were noted in causes linked with the most intense algal blooms. In most of the cases, algal blooms were dominated by diatoms, suggested by the extensive presence of C25 Highly Branched Isoprenoid, a specific biomarker linked with these organisms. The dinoflagellates only recorded a dominant role in blooms in the Krosno location. A comparison of diterpenoids and triterpenoids revealed that terrestrial organic matter was mostly dominated by gymnosperms like conifers from the Cupressaceae, Pinaceae and Podocarpaceae families. Beside these, the molecular evidence of the angiosperms, bryophytes, and fungi was marked. Both geochemical and petrological analyses confirm the minor role of palaeo-wildfires in the land areas near the deposition place of the analysed samples.