Vitrinite Reflectance Measurements Research Articles

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.

Understanding the burial history and the hydrocarbon potential of the late Paleozoic Claromecó foreland Basin (Southwestern Gondwana, Argentina) by combining organic geochemistry, organic petrology, and thermal modeling

The Claromecó foreland Basin (Carboniferous–Permian; southern Buenos Aires province, Argentina) is key to understanding the paleotectonic evolution of the southwestern Gondwana margin and is relevant to energy resource exploration. This study reconstructs the thermal and burial history of the Claromecó Basin by integrating geochemical data, organic petrology, and thermal modeling techniques. Cores samples of the Tunas Formation (Pillahuincó Group, Early Permian) were studied. A 1D thermal model was constructed, calibrated with vitrinite reflectance measurements (VRo %), and corroborated with fluid inclusion and apatite fission track data from previous studies. Rock-Eval pyrolysis results show TOC% values ranging from 0.13 to 60.35 wt%. The Hydrogen index (HI < 50 mg HC/g TOC) and Oxygen index (OI < 50 mg CO2/g TOC) indicate the dominance of Type III and Type IV kerogens, most likely resulting from the thermal maturation of an original Type III kerogen. Petrologic observations confirm the presence of macerals from the inertinite group, as well as minor amounts of vitrinite and liptinite. The Tmax displays a temperature range mostly from 460 to 610 °C. The VRo % values range from 1.5 to 2.0%. Geochemical data combined with VRo % measurements confirm a late catagenesis to metagenesis stage within the wet to dry gas window for coals and organic-rich strata.In order to constrain the thermal evolution of the basin infill, different scenarios were tested by varying the heat flow and the missing section thickness associated with the uplift and erosion of the basin (Permian–Cenozoic unconformity). The best calibration results were obtained with an erosion thickness of 3000 up to 4200 m and paleo heat flow peaks of either 60 or 80 mW/m2 during the Lower Permian–Lower Cretaceous. The Tunas Formation was deposited and buried during the Permian–Triassic (Gondwanides Orogeny phase), reaching a maximum temperature of 180 °C. The results obtained by combining geochemical analysis, organic petrology, and thermal modeling techniques indicate that the coal beds of the Tunas Formation could have a current potential as gas-prone source rocks. Despite that, the hydrocarbon generation capacity of coal levels is currently low due to the high percentage of residual (Type IV) kerogen. Further research could help clarify if the hydrocarbons potentially expelled by these source rocks have been lost due to migration or could be trapped somewhere in the basin.

Vitrinite Reflectance Suppression Revisited

Vitrinite Reflectance Suppression Revisited

The Early Aptian Oceanic Anoxic event (OAE-1a) of the uppermost M'Cherga formation of northern Tunisia: Geochemical characterization and inferred petroleum potential

The Early Aptian organic-rich deep marine deposits of the upper Member of the M'Cherga Formation (Valanginian-Aptian) of northern Tunisia were studied based on a multidisciplinary approach including biostratigraphy, sedimentology and organic geochemistry. This study is based on the analysis of 128 samples collected from three sections (Oued Bazina, Djebba and Tel Ghozlene) selected from the salt dome zone (SDZ) and one section of Jebel Oust, situated westward of the Tunisian range. This work is supplemented by previous research undertaken on Oued Zarga and Jebel Ammar sections. Taxonomic analysis of previous and new data (ammonites and planktonic foraminifera) indicate that three informal lithological units rich in organic matter (U1, U2 and U3) are of Early Aptian age, covering both Blowiella blowi and Leupoldina cabri planktonic foraminiferal zones and indiscriminate Lowermost Aptian to the Deshayesites deshayesi – Dufrenoyia furcata ammonite Zones interval.The Rock-Eval analytical results indicate that the studied Early Aptian strata are relatively rich in total organic carbon (TOC) content with values reaching 4.6 % within the U3 (Leupoldina cabri biozone). The latter occurring in the different studied sections constitutes an important deepening phase related to a global sea-level rise testified by the development of well laminated platy limestones containing abundant ammonites and radiolaria. This unit (U3), covering Leupoldina cabri planktonic foraminiferal zone and Deshayesites deshayesi to Dufrenoyia furcata ammonite Zones interval records the Oceanic Anoxic Event -1a (OAE-1a).The palynofacies assemblages show that the organic matter is mainly represented by amorphous particles. The Tmax values ranging from 437 °C to 456 °C (Mean Tmax: 446 °C) and the measured vitrinite reflectance ranging from 0.79 to 1.03 %, indicate that most samples are early mature except for those of the Tel Ghozlene (TG) section which are within the peak oil-generation-window. Lateral facies and thickness variation, in addition to the organic matter distribution throughout the studied domains, strongly suggest the imprint of salt tectonics both on the sedimentological pattern and associated anoxia during the Aptian. Maturation of the organic-rich facies occurred during the Upper Cretaceous-Paleogene compressional phase and associated salt dome remobilization. Source rocks, developed in the Upper Member of the M'Cherga Formation, are attributed to the OAE1a Event and should be considered when reviewing the petroleum potential of conventional and unconventional resources in northern Tunisia.

PETROGRAPHIC EVALUATION OF OKOBO COAL, NORTHERN ANAMBRA BASIN, NIGERIA

Petrographic studies have been carried out on coal samples from Okobo coal deposit in the northern Anambra Basin of Nigeria. The studies were carried out primarily to determine the petrographic characteristics of the coal based on its composition and vitrinite reflectance. Maceral characterization reveals the presence of the three maceral groups; vitrinite, liptinite and inertinite in all the samples. Generally, the proportion of the vitrinites and inertinites are higher than the liptinites in the samples. On mineral matter-free basis, the coal, on average, contains 65.10 % vitrinite, 11.30 % liptinite and 23.60 % inertinite. With mineral matter counted, on average, it consists of 57.10 % vitrinite, 10.20 % liptinite, 21.50 % inertinite and 11.20 % mineral matter. The coal, on average, also contains 67.30 % reactives (vitrinite + liptinite) and 32.70 % inerts (inertinite + mineral matter). It has mean vitrinite reflectance measurement of 0.54 % Romax on average. These petrographic characteristics suggest that the coal does not possess coking qualities suitable for coke making blends for metallurgical processes such as iron and steel manufacture thereby placing it on low quality and non-coking. However, it is good for electricity generation. The coal is appropriate in heating boilers and ovens in industrial heating process. The cement, glass, ceramics, paper and brick industries can use it for this purpose.

3D basin modeling of the Hils Syncline, Germany: reconstruction of burial and thermal history and implications for petrophysical properties of potential Mesozoic shale host rocks for nuclear waste storage

AbstractJurassic sedimentary sequences suitable for nuclear waste storage in northern Germany consist of organic-lean claystone and were uplifted to &lt; 100 m depth in the Hils Syncline area (southern Lower Saxony Basin). This Hils Syncline, showcasing a northwestward increase in thermal maturity, facilitates the study of shale petrophysical properties influenced by burial history. This study introduces a 3D-thermally calibrated numerical model of the Hils Syncline area to analyze its geodynamic evolution and maturity variations. It provides new vitrinite reflectance and sonic velocity data for modeling calibration and erosion estimation. The Hils Syncline area has undergone continuous subsidence, interrupted by a Cretaceous uplift documented by an erosional unconformity. During the latest Early Cretaceous, Jurassic rocks underwent maximum burial reaching up to several thousand meters depth and temperatures up to 160 °C in the northwest. The Late Cretaceous inversion caused stronger erosion towards the northwest removing up to 3300 m of sediment compared to about 1300 m in the south, according to vitrinite reflectance-based estimations. Numerical modeling results along the study area indicate decreasing porosity and permeability northwestward with increasing thermal maturity. Porosity and vertical permeability decreased to 5–14% and 2.8 × 10–23 to 1.5 × 10–19 m2 [1 mD = 10−15 m2], respectively, while vertical thermal conductivity increased to 1.30–2.12 (W/m/K). These trends of porosity/permeability and thermal conductivity with burial align with sonic velocity and published experimental porosity data, except for the thermally most mature region (Haddessen). This anomaly is tentatively attributed here to localized overpressure generation in the Posidonia Shale during maximum burial, affecting both the underlying Pliensbachian and overlying Doggerian units. Graphical abstract 3D numerical model of the Hils Syncline and surrounding area revealing that a northwestward increase in maximum burial resulted in higher temperatures and varying maturity levels. While most locations align well with calibration data (i.e. measured vitrinite reflectance and porosity), discrepancies arise in the Haddessen/Bensen area. The mismatch between porosity, vitrinite reflectance, and sonic velocity response indicates local overpressure in the northernmost region mainly during the Cretaceous. It was likely caused by gas generation in the Posidonia Shale affecting nearby Lower and Middle Jurassic units.

Hydrocarbon Source Rock Evaluation of the Lucaogou Shale in the Periphery of Bogeda Mountain (SE Junggar Basin, China) and Its Implications for Shale Oil Exploration: Insights from Organic Geochemistry, Petrology, and Kinetics Pyrolysis

Since the discovery of the vast Jimusaer shale oilfield in the southeastern Junggar Basin in 2012, there has been considerable interest in neighboring areas around Bogeda Mountain that have shale oil potential. The primary productive interval in the basin, the Middle Permian Lucaogou Formation (P2l), is well-developed in the areas of Qitai, Mulei, Shiqiantan, Chaiwopu, and Miquan. In this study, we conducted an assessment of the hydrocarbon generation potential of the P2l in these five areas and compared it with that of the P2l in the Jimusaer oilfield, which were determined by GC-MS, total organic carbon (TOC) and vitrinite reflectance (Ro) measurements, Rock-Eval pyrolysis, and organic petrology to investigate the type, origin, thermal maturity, hydrocarbon potential, and oil/gas proneness of organic matter in the P2l. Additionally, we applied open-system pyrolysis of hydrocarbon generation kinetics to explore differences in hydrocarbon generation and expulsion across various P2l mudstone/shale in the southeastern Junggar Basin. The findings of this study revealed that the P2l shale in Qitai and Miquan areas contains more abundant and lower thermally mature organic matter (early mature–mature stage), characterized by primarily Type II1–I kerogen, similar to that found in the P2l shale of the Jimusaer oilfield. Conversely, the P2l shale in Mulei, Shiqiantan, and Chaiwopu contains less abundant and more thermally mature organic matter (mainly mature–highly mature stage), dominated by Type II2–III kerogen. Consequently, shale in these areas is considerably less desirable for oil exploration compared to the Jimusaer shale. The semi-deep to deep lake facies in Miquan and Qitai exhibit the most promising exploration potential. This study can serve as a guide for shale oil exploration in the southeastern Junggar Basin.

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

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

Maturity Parameter of Carbonaceous and Coaly Matter Revealed through Raman Spectroscopy

Abstract This article presents the results of ten coal samples of sub- bituminous rank collected from working mines in Chhattisgarh, India, and subjected to proximate and ultimate analysis, organic petrology and Raman spectroscopic study to reveal their maturity parameters and structural characteristics of carbonaceous materials. Vitrinite reflectance measurement was also performed to understand the maturity parameter, with values ranging from 0.35% to 0.57%. The research is unique as it combines petrological, geochemical and spectroscopic technique on coals of Hasdeo basin. Conventional parametei; volatile matter ranges from 21.83 and 33.68% suggesting low maturity. The ash yield values range from 12.04 and 26.61%. Petrographically, the coals are vitrinite rich ranging from 53.95 to 63.47% while the inertinite group range from 17.9 to 29.2%. The liptinite concentration the samples remain below 10%. The maceral constitution of the coals indicates carbonaceous materials undergoing early diagenetic phase. The Raman results showed the presence of the D and G bands, two prominent spectral signatures, which are typical of natural materials rich in carbon. The Raman shift recorded for the D band ranges from 1348 to 1385 cm-1 and for the G band, the Raman shift was recorded between 1607 to 1616 cm-1. The ratio of the various parameters derived from the two bands aid to understand the material response to the changing physical and chemical variables in the geological setup. The intensity ratio of the ID/IG band ranged from 0.15 to 0.79 (average 0.50), while the (G-D1) parameter ranges from 225 to 260 indicating heterogeneity in the samples. However; the ratio of AD1/AG did not show any regularity, with values ranging from 0.07 to 1.85. The investigation elucidates that by integrating Raman spectroscopy analysis with vitrinite reflectance (VRo), we can discern distinctive structural attributes characteristic of immature kerogen. Furthermore, the petrological, proximate, and ultimate data collectively corroborate the carbonaceous, coaly material in its early stages of coalification.

Geochemical pyrolysis, petrographical analysis and burial history reconstructions of the Kazhdumi Formation in the Hendijan and Soroosh oil fields, northwestern Persian Gulf

The Kazhdumi Formation is one of the most important source units throughout the Persian Gulf and surrounded areas that mainly formed from dark, organic rich shales and marls. In this study, source characteristics of the Kazhdumi successions in the Hendijan and Soroosh oilfields (northwestern Persian Gulf) are evaluated using the Rock-Eval pyrolysis, vitrinite reflectance analysis and one-dimensional thermal modeling. The Rock-Eval data suggest good to very good and poor to fair hydrocarbon potentials for the studied formation in the Hendijan and Soroosh oil fields, respectively. In addition, pyrolyzed data reveal that the successions mainly contain kerogen type II in the Hendijan and kerogen type III in the Soroosh oil fields. Also the Tmax values and vitrinite reflectance measurements show that the Kazhdumi Formation has reached to the oil generation phase in the Hendijan, whereas this formation is immature in the Soroosh Field. Moreover, reconstructions of thermal history exhibit that variations in maturity are linked to the Kazhdumi burial depth and the values of basin heat flow. Eventually, the combination of results indicate that the Kazhdumi hydrocarbon generation in northwestern Persian Gulf increase considerably towards the Dezful Embayment.

Estimation of uplift and erosion in the Miri area of northwest Sarawak, Malaysia: A multidisciplinary approach

The question of uplift in the Sarawak Foreland is addressed in a multi-disciplinary approach, namely by assigning surface vitrinite reflectance measurements to depth, and by vitrinite reflectance-to-depth conversion using functions from two previous studies. Additional erosion and uplift data were obtained by comparing eroded anticlinal crests with adjacent synclines and their preserved sediments. The combined data pool suggests two types of uplift (I) a regional uplift in the Neogene affecting the entire coastal area, and (II) a tectonically focused uplift. The amount of the latter uplift and erosion is directly linked to rise of anticlinal structures during the Upper Pliocene, with a total uplift ranging from 700 to 4,000 m in areas along prominent regional faults. Within a very short time window major sedimentation, folding, trap formation and trap destruction took place both as a consequence of folding and erosion. Only anticlines in the offshore and the proximal onshore appear to have survived without major crestal erosion. Since the end of the Pleistocene, a rise of foreland sections by some 132 m is recognized. The rapid Pliocene burial and the erosion that consequently removed the overburden thereafter may have negatively affected the petroleum system and hydrocarbon accumulation within the Miri area, which was left largely intact only in the Siwa-Seria anticlinal trend. All anticlines were targeted by petroleum exploration. However, only the Siwa-Seria trend has proved to be economically successful. This has highlighted the significance of overburden in relation to depth of burial and the thermal effect needed to mature the source rocks capable to generate hydrocarbons.

Utility of fluid inclusion paleo-temperature in petroleum system modelling: A case study from western offshore, India

The paleo-temperature (Th) data from fluid inclusions are utilized for thermal history modelling using PetroMod software. Generally, bottom hole temperature (BHT) and vitrinite reflectance (Ro) measurements are widely used in petroleum system modelling (PSM) in the oil industry for calibration purposes. Th representing the minimum temperature of fluid entrapment estimated from fluid-inclusion study provides extra support to build the thermal models for PSM. Fluid inclusion parameters along with Rock-Eval pyrolysis analysis have been used to predict the maturity of oil in terms of API gravity as well as the maturity of source rocks respectively. Two exploratory wells RV-1 (Mumbai Offshore Basin) and KK4C-A-1 (Kerala-Konkan Offshore Basin), India were examined and the Th from most of the fluid inclusions of wells RV-1 and KK4C-A-1 fell in the oil window range of 60–140 °C suggesting thermal conditions favourable for oil generation in both of the wells. Th of coeval aqueous inclusions along with the Hydrocarbon Fluid inclusions (HCFIs) was used to calibrate PSM. Vital parameters show that source rocks of well RV-1 are mature and that of well KK4C-A-1 are immature. Two sets of PSM are created in terms of generation and expulsion for the dry wells RV-1 and KK4C-A-1 and calibrated each well using fluid inclusion Th and BHT. From the fluid inclusion analysis method, it is evident that hydrocarbon generation happened in both wells and the paleo-temperature indicates that the formations of both wells were subjected to temperatures in the oil window range, even though it was designated as dry wells in the present scenario. The present study highlights the application of fluid inclusion paleo-temperature (Th) during calibration instead of commonly used methods. We could obtain desirable and accurate data output from PSM using Th calibration.

Organic petrography and palynofacies of the Upper Cretaceous (Campanian-Maastrichtian) organic rich strata of the Quseir-Safaga Region, Eastern Egypt

The Campanian-Maastrichtian organic-rich rocks in the Quseir – Safaga Region in the Eastern Desert of Egypt have growing economic importance. This economic importance is discussed in many of previous studies by many of different geological tools that lacked the petrographic examination of organic matter occurrence modes. The organic petrography provides the essential tools for microscopic analysis to study the organic matter that are applied for the first time in the present study. The palynofacies and organic petrography are used in the present study to investigate the nature of the organic matter and the paleoenvironmental settings that controlled their distribution in the Duwi and Dakhla formations in the Younis and Mohamed Rabah areas (Egypt). The study of dinoflagellate cysts allowed the identification of the biostratigraphically characteristic assemblages of the Campanian – Maastrichtian in the Eastern Desert including Assemblage II/I (in Duwi Formation) and Assemblage III (in Dakhla Formation) that were identified in Egyptian oil shales of this time range. The identified assemblages are correlated with local and regional studies to delineating the formal biozonation. The organic matter in the Duwi Formation comprises rich fluorescent amorphous organic matter, prasinophytes, sporomorphs, dinocysts as well as a minor terrigenous component of phytoclasts. In the Dakhla Formation, the fluorescent AOM is found to be highly mixed with Botryococcus in addition to prasinophytes and marine palynomorphs. The paleoenvironmental analysis indicates deposition in distal anoxic to proximal suboxic marine conditions with high paleoproductivity. The results are confirmed with the inorganic geochemical composition of redox sensitive elements. The analysis reveals that the Younis section is differentiated into two palynofacies types (proximal, suboxic high productivity in the Duwi Formation and distal anoxic in the Dakhla Formation). The Mohamed Rabah section, one palynofacies type is recognized that is proximal, suboxic high productivity. The principal component analysis is used to interpret the distribution of organic matter abundances. The kerogen types are distinguished based on the area percentages of the fluorescent organic matter and application of kerogen plots. The samples of both formations fall within oil prone kerogen type II. The spore coloration and measured vitrinite reflectance indicate immature kerogen in the studied sections. The organic matter in the studied rocks comprises hydrogen rich compounds that can be treated for direct composition or retorted to extract shale oil. The heavy metals concentrations are significant and present technology will increase its economic value.

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

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

Characteristics of oils and their potential source rocks from the Cherokee Platform, Oklahoma

The Woodford Shale is the most prolific source rock in the Anadarko Basin and Cherokee Platform and, over the past decade, it has become renowned for its high unconventional hydrocarbon potential. Recent Woodford Shale studies have emphasized facies heterogeneity based on lithology, sequence stratigraphy, and geochemical analyses. Data presented in this paper focus on the organic geochemical characterization and genetic relationship between the Woodford Shale and oils in the Cherokee Platform area, Pottawatomie County, Oklahoma. The shale samples were screened by total organic carbon (TOC) and Rock-Eval (RE) that indicate a high-quality Type I/II kerogen. Vitrinite reflectance measurements (VR%) of 0.59% for the Woodford Shale indicate the samples are at an early maturity stage in this area. The Woodford Shale generally has been subdivided into three members (Upper, Middle, and Lower), but in this study only the Upper and the top part of the Middle Woodford were characterized. Both intervals alternate between suboxic and anoxic depositional conditions, along with water column stratification and episodic euxinia or photic zone anoxia (PZA). A PZA episode has been described for Upper Woodford for the first time where C40 carotenoids and aryl isoprenoids show maximum abundance.The second part of the investigation involved oils, collected from wells in the area, and a detailed correlation with the Woodford Shale. The oils showed a close correlation with the Woodford, but maturity based on biomarkers may suggest a deeper source rock with equivalent organofacies. Many of the oils examined showed varying levels of biodegradation and possible mixing with a lighter more mature oil. The oils were compared with each other to determine possible relationships and assess the petroleum system on the southern Cherokee Platform.

The Combustion Profiles of the Lafia-Obi Coals: Implication for Electricity Power Generation

This paper aims to understand the combustion profiles of the coal samples in the Lafia-Obi axis, Middle Benue Trough (MBT), for consideration as a potential energy source for electricity power generation. Despite efforts and commitment from renewable energy sources to account for a significant share of the total electricity supply, coal remains the most important electricity-producing fuel globally. Currently, there is growing energy demand, as many industrialized and developing countries continue to rely on coal for electricity power generation in the next few decades to come. The Benue Trough is a failed arm of the triple ‘RRr’ junction of an inland sedimentary basin that extends in a NE-SW direction from the Gulf of Guinea in the south, to the Chad Basin in the north. A total of nine (9) grab coal samples were obtained from 3 coal localities in the Lafia-Obi environment, the proximate analysis was conducted on the coal samples using a Perkin Elmer Thermogravimetric Analyzer. The results show the coals have high volatile matter content, low ash yield, and high calorific value (21.97 MJ/Kg, on areal average). Ultimate data shows that Sulphur values are generally low (areal average of 0.90 %). Vitrinite reflectance measurements were carried out largely on petrographic pellet blocks revealing that they are generally dominated by vitrinite maceral, with an areal average of 80.6 % by volume (mineral-matter free). Lafia-Obi coal is a medium-rank C bituminous coal with high vitrinite and fusinite. The findings obtained from this paper show that the coals in the study area can be used for electricity power generation except for sample 01 with high ash content of 73.03 weight %.

Paleoenvironmental reconstruction of the Permian coal beds in the Paraná Basin (Brazil): evidence from organic geochemical and sedimentological analyses

The Rio Bonito Formation (Paraná Basin) contains the thickest coal beds in Brazil, that are related to peat-swamp developed in coastal depositional systems during the early Permian. This study aims to understand the source of the coal organic matter and to distinguish depositional sub-environments along the coal-bearing interval from the southern border of the basin. The analysis was performed on sedimentological and stratigraphic data from 10 wells combined with organic petrology and geochemistry of the three coal beds. Samples were collected in different key beds from the SG-14 well, in different and strategic depths at the base (218.0 m), at the intermediate (209.0 m), and at the top (181.0 m) of the coal-bearing interval. The vitrinite reflectance measurements of the selected samples, Tmax values, C29 ααα 20 S/(20 S + 20 R) ratio, and the absence of peak Ts (and presence of peak Tm) revealed the organic matter in the coal-bearing interval is thermally immature, suggesting low burial depth for the Rio Bonito Formation in the study region. Maceral composition showed predominance of vitrinite and inertinite in the three coal samples. Rock-Eval pyrolysis data indicate that the coal beds are composed of type III kerogen in the three samples, while the biomarkers indicate type II-III kerogen mixtures. The n-alkane distribution profiles suggest dominance of terrestrial organic matter in the samples, with a possible marine contribution at the top of the coal-bearing interval. The pristane/phytane (Pr/Ph) and C27/C29 ααα20 R ratios (regular steranes) revealed sub-anoxic condition and land plants as major organic matter source for basal and intermediate parts of the coal-bearing interval. They also indicate an increased anoxic conditions and possible marine algal contribution toward the uppermost coal level. The presence of cone-in-cone-shaped structures (SG-07 well, depth 157.5 m) and Orbiculoidea fossils (SG-14 well, depth 192.5 m) are indicative of brackish water and support river-marine source mixtures at the top of the coal-bearing interval. The evolutive sedimentation model comprises four paleoenvironments for the Rio Bonito Formation along geological time, in which the basal part of the coal interval is interpreted as overbank deposits in a fluvial depositional system. On the other hand, the intermediate part of the coal-bearing interval was formed in bay-head delta, and the upper part was deposited in the central estuary, both in a tide- and wave-influenced estuarine context.

Reservoir Characteristics and Influencing Factors of Organic-Rich Siliceous Shale of the Upper Permian Dalong Formation in Western Hubei

To elucidate the reservoir characteristics of organic-rich siliceous shale of the Upper Permian Dalong Formation in western Hubei, this study focused on the drilling cores of Well ED-2. Various techniques, including a mineral composition analysis, an organic carbon content analysis, a vitrinite reflectance measurement, a total porosity determination, field emission scanning electron microscopy (FE-SEM), and low-pressure CO2 and N2 physical adsorption tests, were employed to analyze the mineralogy, organic geochemistry, total porosity, and pore structure characteristics. Additionally, the factors influencing the reservoir performance of the Dalong Formation shale were investigated. The results indicated that the Dalong Formation’s shale was characterized as an organic-rich siliceous shale. Organic matter was mainly of sapropelic type, with a relatively high thermal evolution degree and Ro ranging from 2.59% to 2.76%. The total porosity of the Dalong Formation’s siliceous shale was low, indicating poor reservoir properties. Organic matter pores were highly developed, mainly the ones formed after the hydrocarbon generation of solid asphalt. Micropores and mesopores were the dominant pore types in the shale, with macropores being significantly less abundant. The study further revealed that the pore volume and specific surface area exhibited a significantly positive correlation with total organic carbon (TOC) content and clay minerals, while demonstrating a weak negative correlation with quartz content. The comprehensive analysis revealed that there were two factors contributing to the poor physical properties of organic-rich siliceous shale in the Dalong Formation. Firstly, in siliceous shale with a high quartz content, the siliceous component was partly derived from the siliceous cementation of hydrothermal fluids. This process led to the formation of secondary quartz that filled intergranular pores, resulting in a decrease in macropore volume, total porosity, and a weak negative correlation with quartz content. Secondly, in siliceous shale with a relatively high clay mineral content, the organic matter was subjected to stronger compaction due to the relatively low content of brittle minerals. This compaction caused the destruction of most macropores, leaving behind primarily micropores and mesopores. Consequently, the average pore size decreased, leading to poor physical properties.

The paleoenvironmental and thermal histories of the Permian Irati Formation shale in the Paraná Basin, Brazil: An integrated approach based on mineralogical and organic imprints

Mineralogical assemblages and organofacies are important sources of information to recover the paleoenvironmental and thermal histories of shale deposits. In this study, a detailed qualitative and quantitative characterization of the Permian Irati Formation (Assistência Member) shale is based on mineralogical (XRD and SEM-EDS) and organic components (TOC, Rock-Eval pyrolysis, organofacies, TAI, fluorescence and vitrinite reflectance measurements) and provides integrated data about sediment provenance, depositional environment, diagenesis, and thermal history, while supporting interpretations on the Paraná Basin (PB), Brazil, paleogeography and its correlation to the southwest Gondwana. The results revealed a prevailing type I/II kerogen, with type III kerogen being also present but mainly confined along the paleoshoreline of the PB. The dominance of fluorescent amorphous organic matter (AOM) combined with framboidal pyrite suggests microbial activity in an anoxic-dysoxic neritic-marine paleoenvironment. Additionally, common to abundant well-preserved phytoclasts, as well as the occurrence of Botryococcus braunii, indicates freshwater influx in a brackish marine depositional setting. Immature to early-oil window thermal maturities prevail across the PB, according to the organic maturation indicators. The combined analysis between the organic matter evolution with clay mineralogy, such as the occurrence of interstratified clays (e.g., I/S) and its positive correlation with depth suggest that burial diagenesis reached the transition to early catagenesis on the north, southeast, and south of the basin, attributing a shale oil potential for the Irati Formation on a regional scale. Local scale imprints of the Early Cretaceous Paraná-Etendeka Large Igneous Province (LIP), and its thermal effect in the Irati Formation shale components, are recorded as clay authigenesis (e.g., smectite webby texture and clay coating development), crystallization of minerals by low to high-grade of thermal alteration (e.g., corrensite, talc, lizardite and diopside), and by local scale gas-window maturities. Such thermal alteration, identified in the proximity to intruded sills and dykes, led to a heterogeneous organic maturation pattern with implications on shale gas and shale oil potential of the Irati Formation shale, demonstrating that these subjects in the Paraná Basin should be assessed locally.

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

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