Hydrocarbon Generation Potential Research Articles

Geochemical characterization of Upper Cretaceous organic-rich deposits: Insights from the Azraq Basin in Jordan

Cretaceous sedimentary successions in Jordan are among the most promising unconventional global petroleum resources. The Upper Cretaceous deposits in the Azraq Basin in Jordan were analyzed using Rock-Eval pyrolysis, stable carbon isotopes, vitrinite reflectance, and biomarkers, as well as 1D basin modeling. This study aims to evaluate source input, depositional environment, burial history and potential for hydrocarbon generation of the Upper Cretaceous organic-rich deposits in Jordan. The Upper Cretaceous samples exhibit variable source rock potential. Maastrichtian samples are very good, primarily oil-prone, while Campanian and Cenomanian samples range from fair to poor, with Turonian samples showing good petroleum generation potential. Thermal maturity analysis of Cretaceous samples reveals higher maturity in Turonian and Cenomanian samples compared to the thermally immature Maastrichtian and Campanian samples based on the maximum temperature of pyrolytic hydrocarbons generation, vitrinite reflectance, production index and biomarker indicators. The molecular fossils data suggest that the organic matter of these source rocks was primarily of marine phytoplankton origin, with considerable contributions from microbial biomass, and deposited under oxygen-depleted bottom water conditions. Additionally, the resemblance in molecular composition between Cretaceous source rocks and crude oil samples suggests a common origin for the hydrocarbons. The highest contents of organic matter have been recorded at the top of the Maastrichtian and at the bottom of the Turonian sections. These findings correspond with Maastrichtian upwelling deposits in North Africa and the Middle East, as well as with deposits from the Cenomanian-Turonian Oceanic Anoxic Event (OAE2).

The evaluation of hydrocarbon generation potential, 2D modeling of sedimentary basin, and tracing hydrocarbon migration pathway in the Garmsar Block, Central Iran Basin

The evaluation of hydrocarbon generation potential, 2D modeling of sedimentary basin, and tracing hydrocarbon migration pathway in the Garmsar Block, Central Iran Basin

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.

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.

Hydrocarbon Generation Potential and Organic Matter Enrichment Mechanism of the Cambrian Marine Shale in the Tadong Low Uplift, Tarim Basin

AbstractCambrian shales in China and elsewhere contain abundant oil and gas resources. However, due to its deep burial and limited outcrop, there has been relatively little research conducted on it. The Cambrian shale of the Tadong low uplift in the Tarim Basin of western China, specifically the Xidashan–Xishanbulake Formation (Fm.) and overlying Moheershan Fm. provide a case study through the use of organic petrology, mineralogy, organic and elemental geochemistry, with the aim of analyzing and exploring the hydrocarbon generation potential (PG) and organic matter (OM) enrichment mechanisms within these shale formations. The results indicate that: (1) the Cambrian shale of the Tadong low uplift exhibits relatively dispersed OM that consists of vitrinite‐like macerals and solid bitumen. These formations have a higher content of quartz and are primarily composed of silica‐based lithology; (2) shale samples from the Xidashan–Xishanbulake and Moheershan formations demonstrate high total organic carbon (TOC) and low S2 content. The OM is predominantly type I and type II kerogens, indicating a high level of maturation in the wet gas period. These shales have undergone extensive hydrocarbon generation, showing characteristics of relatively poor PG; (3) the sedimentary environments of the Xidashan–Xishanbulake and Moheershan formations in the Tadong low uplift are similar. They were deposited in warm and humid climatic conditions, in oxygen‐deficient environments, with stable terrigenous inputs, high paleoproductivity, high paleosalinity, weak water‐holding capacity, and no significant hydrothermal activity; and (4) the relationship between TOC and the paleoproductivity parameter (P/Ti) is most significant in the Lower Cambrian Xidashan–Xishanbulake Fm., whereas correlation with other indicators is not evident. This suggests a productivity‐driven OM enrichment model, where input of land‐derived material was relatively small during the Middle Cambrian, and the ancient water exhibited lower salinity. A comprehensive pattern was formed under the combined control of paleoproductivity and preservation conditions. This study provides valuable guidance for oil and gas exploration in the Tarim Basin.

Quantitative analysis of molecular structure characterization of different liptinite-rich coals using FTIR spectroscopy

As one of the important components in low-rank coals, liptinite plays an indispensable role in the formation and utilization of coal, thus, understanding the occurrence and structures of liptinite-rich coals provides a theoretical basis for the origin and clean utilization of coals. In this study, the occurrence of liptinite and the functional groups and molecular structure of different liptinite-rich coals were quantitatively characterized by using optical microscope and Fourier transform infrared spectroscopy (FTIR), respectively. The results showed that the sample JS-7 from Yunnan Province mainly enriched sporinite and bituminite, the sample JS-15 from Yunnan Province is rich in dispersed resin and the amber-rich coal from Liaoning Province mainly contains bulk resin. The FTIR results indicated that the amber-rich coal, the sample JS-7 and pure amber (Liaoning Province) consist mainly of trisubstituted benzene. The sample JS-7 has the highest content of trisubstituted benzene (63.4%) due to the high content of sporinite and bituminite. The sample JS-15 is mainly composed of tetrasubstituted and pentasubstituted benzene, which may be relevant to the cyclization of aliphatic chains and the decarboxylation reaction of benzene rings. The CC group has not been detected in the sample JS-7 and pure amber. The FTIR structural parameters indicate that the pure amber has the lowest maturity, the lowest degree of aromatization, but the highest hydrocarbon generation potential. The highest CH2/CH3 group value (14.69) and the lowest A factor value (0.36) of the sample JS-15 indicate a well-developed aliphatic chain structure and lowest hydrocarbon generation potential, respectively, which probably caused by the low content of CO group.

Molecular structure and evolution mechanism of shale kerogen: Insights from thermal simulation and spectroscopic analysis

During thermal evolution, the kerogen in shale formation undergoes significant chemical, structural and compositional changes, continuously influencing the shale storage capacity, hydrocarbon generation potential, and gas occurrence state. This study systematically examines the chemical structural changes during the thermal evolution of Longmaxi shale kerogen using hydrothermal laboratory experiments from 420 to 850 °C. Additionally, a range of characterization techniques, including Fourier Transform Infrared (FTIR) spectroscopy, Raman spectroscopy, High-Resolution Transmission Electron Microscopy (HRTEM), X-ray Diffraction (XRD), and Solid-state 13C Nuclear Magnetic Resonance (13C NMR), were employed to systematically investigate the kerogen structure and its evolution patterns. Results indicate that Longmaxi Formation kerogen comprises a large molecular carbon framework with aromatic structures, long-chain aliphatic components, and oxygen-containing functional groups. As thermal maturity reaches 2.6 %, the alignment of aromatic fringes gradually increased, with over 60 % aligning in the main direction. Throughout thermal evolution (1.9–3.2 %), fringes in the 5–10 Å range within aromatic structures peak at over 20.45 %, with fringes over 50 Å rapidly increasing from 3 % to over 15 %. Early in the thermal evolution, the long-chain aliphatic component of the kerogen decreases rapidly and part of the structure forms small aromatic rings through aromatisation. The mature to over-mature stage can be divided into three phases: 1) 1.7–2.4 % (loss of oxygen-containing functional groups), 2) 2.4–3.5 % (formation of larger aromatic structures via condensation reactions), 3) over 3.5 % (continued aggregation of aromatic rings, resulting in an increase in the length of aromatic fringes). At a macroscopic level, this induces changes in kerogen pore structure and carbonization features. This study thus provides new insights into the thermal evolution of shale kerogen, which in turn improve understanding of shale reservoirs for hydrocarbon exploitation.

Investigating the hydrocarbon potential of the Paleogene coal seams in Kapuni field, Taranaki basin, New Zealand: Implications for coal-oil correlation

Hydrocarbon generation in Taranaki Basin, New Zealand, has been proven in several source rocks within the syn- and post-rift basin-fill sedimentary successions. These source rocks are mainly hosted in the marginal and deep marine Upper Cretaceous shales, which generate marine and terrigenous oils. Some of the terrigenous oils could have been linked to the Paleogene coals; however, the capability of these coals to generate and expel liquid hydrocarbons is poorly-investigated. In this study, we present organic geochemistry, kerogen petrography, wireline logging, and basin modelling to evaluate the hydrocarbon generation potential of the Paleogene coals and coal-rich facies of the Kapuni Group sediments in Kapuni Field, Taranaki Basin. A compositional correlation between oil in the Kapuni Group reservoirs and coal extracts was performed to decipher the oil origin and define its parent source rock. Kapuni oils display high pristane/phytane (Pr/Ph) > 5, low dibenzothiophene (DBT)/phenanthrene <0.1 and high relative abundance of C29 regular steranes >60%, typifying their generation from a terrigenous source rock deposited in an oxic, fluvio-deltaic environment. Similar values were also observed in the muddy coal extracts of Farewell Formation, thereby reflecting a positive coal-oil correlation. The maturity-relevant biomarkers (Ts/Tm trisnorhopanes; C29 steranes isomers, and 22S-, 22R C32 homohopanes) are similar in both oils and Farewell coal extracts confirming oil expulsion from Farewell coals during the peak oil window maturity. These results demonstrate the generation and expulsion of coal-oil, thereby shedding light on the prospectively of the Paleogene plays in the Taranaki Basin.

Level of thermal maturity estimation in unconventional reservoirs using interval inversion and simulating annealing method

AbstractThis study presents a novel geophysical approach for estimating the level of thermal maturity (LOM) in unconventional hydrocarbon reservoirs using well log data. LOM is a crucial parameter for assessing the hydrocarbon generation potential of source rocks, but it traditionally relies on laboratory measurements of core samples, which can be time-consuming and costly. The proposed method combines two techniques: interval inversion for estimating total organic carbon (TOC) content from well logs and simulated annealing (SA) optimization for deriving LOM from the estimated TOC. The interval inversion method enables accurate TOC estimation by jointly interpreting multiple well logs over depth intervals, overcoming limitations of conventional point-by-point inversion. Using the estimated TOC, the SA algorithm optimizes an energy function related to Passey's empirical TOC-LOM relationship, iteratively finding the optimal LOM value that best fits the well log data. This approach provides a continuous in situ LOM profile along the borehole without requiring core measurements. The effectiveness of the method is demonstrated through case studies on datasets from the North Sea (Norway), the Pannonian Basin (Hungary), and the Kingak Formation (Alaska). The LOM estimates show good agreement with reported maturity levels and allow reliable reservoir characterization. Statistical analysis confirms the robustness and accuracy of the results. By reducing dependence on core data, this integrated inversion-optimization workflow streamlines the reservoir prospecting phase, enhancing operational efficiency. The method holds promising applications across diverse geological settings for cost-effective evaluation of unconventional hydrocarbon plays.

Assessment of the source rock potential in the Sirka and Giddi collieries of South Karanapura coalfield, Jharkhand, India: Insights from megaflora, palynology, and geochemistry

Permian deposits in the Indian Peninsula have long been a significant source of coal and have great potential for hydrocarbon exploration. Here we present results of megafloral, palynological, and geochemical analysis of the Late Artinskian-Kungurian sediments in the South Karanpura coalfield to assess hydrocarbon generation potential, kerogen types, depositional settings, and thermal maturation. The results suggest anoxic to oxic depositional environments with fluctuating water levels, influenced by terrestrial inputs. The Sirka colliery is considered to be most favorable for hydrocarbon generation due to the palaeodepositional setting dominated by flooded palaeomires. The dominance of degraded organic matter and the rarity of opaque phytoclasts suggest type II/III to type III kerogen material in the palaeomire of the Srika succession, characterized by low-energy dysoxic to anoxic conditions. The thermal maturation values (Tmax 429℃) and the production index (0.01–0.02) indicate that the Sirka area has immature kerogen, but the Giddi colliery has a relatively higher Tmax (average 435℃) placing the studied sample within the mature zone. However, due to deposition in the oxidized swamp, Giddi C has poor potential for hydrocarbon generation, showing that type III/IV material has charcoal input into the sediments. Our findings contribute to global knowledge of coal formations’ oil and gas storage capacity, which has implications for energy resource assessment and exploration strategies.

Controls and Geological Significance of Macerals in Hybrid Shales: A Case Study on the Gaoyou Sag, Subei Basin, East China.

In the Gaoyou Sag located within the Subei Basin, the hybrid shales from the second member of the Funing Formation (E1f2) have been identified as a prolific source of shale oil production, despite their characteristically low organic matter content (TOC < 1.5%). This observation suggests that specific macerals within these hybrid shales demonstrate a pronounced hydrocarbon generation potential, thus unveiling a new frontier for shale oil exploration endeavors. In this study, 16 samples were rigorously extracted from both mudstone and hybrid shale strata within the E1f2. An exhaustive suite of organic and inorganic geochemical analyses was conducted on these specimens. The analyses elucidated several key findings: (1) The maceral composition within the hybrid shales is predominantly comprised of alginite, solid bitumen, and inertinite. Remarkably, the variability of alginite content within the hybrid shales is more pronounced than that observed in high-TOC mudstones. High-TOC mudstones are characterized by a preponderance of lamalginite and a paucity of telalginite, leading to a diminished aggregate hydrocarbon potential. (2) Biomarker ratios (e.g., sterane/hopane, C23 tricyclic terpane/αβ C30 hopane, C24 tetracyclic terpane/C26 tricyclic terpane, etc.) suggest a primary derivation from lower aquatic organisms, with a secondary contribution from terrigenous organic matter within the hybrid shales. (3) The accretion of macerals is governed by an intricate set of factors, including the input of terrigenous detritus, paleosalinity, and paleoproductivity. (4) Alginite is identified as the principal constituent responsible for hydrocarbon genesis in hybrid shales. The proliferation of alginite facilitates the concurrent enrichment of shale oil and organic matter within the hybrid shales of the Subei Basin, illustrating a cooperative mechanism underlying the accumulation of shale oil and organic matter. This indicates that even hybrid shales with scant organic content exhibit considerable potential for shale oil exploration.

Organic matter characteristics and hydrocarbon generation potential of the Middle Jurassic–Lower Cretaceous succession in the Mesopotamian Foredeep Basin, Iraq

Organic matter characteristics and hydrocarbon generation potential of the Middle Jurassic–Lower Cretaceous succession in the Mesopotamian Foredeep Basin, Iraq

Geochemical Characteristics and Hydrocarbon Generation Potential of Coal-Measure Source Rocks in Julu Sag

Geochemical Characteristics and Hydrocarbon Generation Potential of Coal-Measure Source Rocks in Julu Sag

Hydrocarbon-generating potential of the Middle Permian Lucaogou source rock in the eastern Junggar Basin, China

The Middle Permian Lucaogou Formation is the most significant source rock in the eastern Junggar Basin. Previous studies have confirmed its excellent hydrocarbon-generating potential in the Jimsar Sag. However, its potential in other areas of the eastern Junggar Basin remains uncertain. Based on total organic carbon and pyrolysis, organic petrology, hydrocarbon simulation experiments, basin simulation, and combined well-seismic coupling interpretation, this study systematically compares the hydrocarbon-generating potential of the Lucaogou source rock in the Jimsar Sag with other areas of the eastern Junggar Basin. It discusses the sedimentary environment of high-quality source rocks and depicts the distribution of practical source kitchens. The Lucaogou source rocks in the eastern Junggar Basin are oil-prone, dominated by type I–II kerogen, and generally classified as good to excellent source rocks. Nowadays, the area of the Lucaogou source rocks that have entered the main oil-generating window is approximately 11 × 103 km2. Except for the bulge area, the Lucaogou source rocks in the eastern Junggar Basin successively entered the hydrocarbon-generating threshold during the Jurassic and the main oil-generating window in the Cretaceous. The Lucaogou source rocks in the Jimsar Sag and other parts of the eastern Junggar Basin share similar biomarker fingerprints, characterized by relatively low ratios of Pr/Ph, Pr/n-C17, Tm/C30 hopane, C19/C20 tricyclic terpene, and C24 tetracyclic terpene/C26 tricyclic terpene, and high β-carotene content, gammacerane index, and Ts/Tm ratios. These characteristics reflect deposition in a strongly reducing brackish lacustrine environment with parental sources dominated by lower organisms such as algae and bacteria. Generally, the Lucaogou source rocks in the eastern Junggar Basin have an oil-generating intensity of more than 3 × 106 t/km2. Several oil-generating centers with an intensity of more than 5 × 106 t/km2 have developed in the front of the Bogda Mountain, Jimsar Sag, Dongdaohaizi Sag, Wucaiwan Sag, and Shazhang Fault Zone, covering a total area of approximately 12,500 km2. These characteristics of the Lucaogou source rocks promise favorable potential for forming large and medium oil fields. The results further consolidated the oil and gas resources in the eastern Junggar Basin and provided valuable references for exploring future oil and gas fields.

Smectite Illitization Geothermometry of the Upper Indus Basin Hydrocarbon Source Rocks (Pakistan)

Abstract —Smectite illitization geothermometry has been used to assess the thermal maturity and hydrocarbon generation potential of the late Paleocene to early Eocene Patala Formation in the Upper Indus Basin. X-ray diffraction (XRD) detected illite, muscovite, quartz, kaolinite, chlorite, and calcite. Comparison between air-dried (AD) and ethylene glycol (EG)-solvated XRD patterns reveals the absence of discrete smectite and interstratified illite-smectite (I-Sm). Additionally, authigenic illite-2M1 indicates that the Patala Formation has entered the late-stage diagenetic zone or the low anchizone, which lies in the R3 illitization zone. Abundant SiO2 and Al2O3 in the Patala clay fraction indicate the substitution of tetrahedral Si4+ by Al3+ within the smectite interlayers. Likewise, the relative abundance of K2O to CaO and MgO indicates the exchange of K+ with Ca2+ and Mg2+ during smectite illitization. Scanning electron microscopy (SEM) reveals in situ growth of platy illite crystals that form within the R3 zone. Furthermore, the total organic carbon (TOC) of the Patala shale exposed in Tirah suggests a poor to good source rock. The absence of discrete smectite and I-Sm, combined with the detection of discrete illite in the Patala shale, suggests that hydrocarbon might have potentially migrated from the source to the reservoir rock during smectite illitization.

Micro-fracture propagation and numerical simulation of fracture propagation under thermal simulation experiment of organic-rich shale: Chang-7 source rock in Yanchang, Ordos Basin

Organic-rich shale as a high-quality source rock which is usually deposited in a high-temperature and high-pressure environment, and its internal organic matter will gradually transform into hydrocarbon and be discharged from shale. However, shale has polar porosity and permeability, making it difficult for hydrocarbon to be discharged from the shale through the pore throat. The latest research suggests that due to the strong hydrocarbon generation potential of shale rich in organic matter, the pressure generated by hydrocarbon can cause micro-fracture in the shale, leading to the expulsion of hydrocarbon from the micro-fracture. Therefore, this article uses hydrocarbon generation simulation experiments and Comsol Multiphysics to analyze the mechanical characteristics and damage propagation of micro-fracture during shale hydrocarbon generation process. The results show that with the increase of temperature and fluid pressure, micro-fracture of different lengths have different initial fracture pressures, and during the diffusion of micro-fracture, the stress inside the shale matrix and micro-fracture exhibits different diffusion characteristics.

The Impact of Marine Influence on the Hydrocarbon Generation Potential and Process of Upper Paleozoic Coal in the Eastern Ordos Basin, China: Implications for Unconventional Gas Exploration of Coal Measures

The Impact of Marine Influence on the Hydrocarbon Generation Potential and Process of Upper Paleozoic Coal in the Eastern Ordos Basin, China: Implications for Unconventional Gas Exploration of Coal Measures

Assessment of the hydrocarbon potential in the black shales of the Jurassic Khatatba Formation and generated hydrocarbons, North Western Desert, Egypt: Depositional mechanism of organic rich rocks related to syn-rift differential subsidence

Jurassic rocks comprise the main source rocks in the Western Desert of Egypt. In this study, a rare case of Jurassic oil shale occurrence is recorded and studied as an extension of the Khatatba Formation. The study is based on an integrated model for oil shale deposition using seismic data, organic geochemical analyses, and palynomorph thermal alteration assessment to determine the hydrocarbon generation potential of these rocks. The seismic data were used to construct structure and lithofacies models and to relate the facies distribution with the geochemical parameters of the different rock units in addition to examining the lithofacies changes between the study wells adding value to the understanding of the environment of deposition and the structure of the study area. The Zahra, U. Safa, and L. Safa members are affected by two sets of normal faults, the first of which has a downthrown side to the east while the second set has downthrown westward sides. The 3D facies models show that the Zahra Member is composed mainly of limestone encountered in the central parts of the basin, while shale is mostly found in the north. The U. Safa consists mainly of sandstone and the L. Safa consists of sandstone and siltstone. The geochemical evaluation shows organic richness ranging from poor to good for the Zahra, while the Safa shows poor to excellent richness. Kerogen is Type III and IV in most samples. The Zahra samples are immature in the TUT-21X well and mature in only one sample from the AMOUN NE-2X well. The U. Safa samples are immature to marginally mature while the L. Safa samples are marginally mature to mature in the TUT-21X well and immature in the SHAMS-15X well. Palynomorph thermal alteration data confirm the above maturation levels. The bulk and biomarker composition of two oils samples from U. and L. Safa, AMOUN NE-1X well, are similar and indicate a terrigenous source of the kerogen. The oils are not biodegraded but are normal mature oils generated by kerogen that was deposited under oxic conditions. Data integration from this study can be used to show the variation in organic richness (TOC) and thermal maturity (Tmax) in the area between the four wells, which will help define the exploration risk and provide for a new vision for more exploration activity.

Oil-source correlation in the Yangjiang Uplift, South China Sea: A comparative analysis of mathematical and fingerprint methods

In recent years, significant exploration breakthroughs have been achieved in the Yangjiang Uplift. However, the source of crude oil is ambiguous, and the prevailing view suggests a remote hydrocarbon supply. To clarify the source of the crude oil in the Yangjiang Uplift, 30 source rocks and 15 crude oil samples collected from the Wenchang A Sag and Yangjiang Uplift are subjected to Rock-Eval pyrolysis, maceral analysis, vitrinite reflectance, and biomarker analysis, among other experiments. Principal component analysis and hierarchical cluster analyses are performed. The results indicate that the source rocks in the Yangjiang Uplift exhibit robust hydrocarbon-generating potential, with S1 + S2 values ranging between 0.04 and 140.5 mg/g (averaging: 13.54 mg/g), indicative of reaching the oil generation period. Using 13 biomarker compounds, two types of biomarkers are selected to compare the sources of the crude oils: pristane/phytane (Pr/Ph) representing the depositional environment and tricyclic terpanes (TTs) representing the source input. The crude oil in the Yangjiang Uplift can be divided into two types: one with high values of bicadinane-T (T)/C30 hopane and ΣC30-4 methyl sterane/ΣC29 regular sterane and another with a low ratio of (C19TT + C20TT)/C23TT according to the charting method. The investigated crude oil is mixed with the source rocks of the Wenchang A Sag and the Yangjiang Uplift. Furthermore, owing to the differences in the mixing ratios, the crude oil in the study area exhibits two distinct characteristics. Type A is characterized by a higher proportion of the Wenchang A Sag crude oil in the mixture, whereas type B is characterized by a higher proportion of local crude oil. This study establishes that the Yangjiang Uplift boasts large petroleum resources.