Petroleum Generation Research Articles

On the determination of oil charge history and the practical application of molecular maturity markers

Determining the thermal maturity and the charge history of crude oil to any reservoir, has key implications for understanding petroleum generation, accumulation history and hence identification of exploration potential. In this paper we combine studies of several source rock sequences and associated crude oils using quantitative component concentration data in addition to traditional molecular marker ratio parameter approaches. The case history studies include examination of organic-rich sapropelic marine source rocks from the Second White Speckled Shale Formation (2 WS Fm.), in the Western Canada Sedimentary Basin and the upper Jurassic Draupne Fm. in the North Sea and their related oils. Each molecular component in the petroleum has a unique concentration evolution curve during source rock maturation, in which n-alkanes, light aromatic hydrocarbons and diamondoid hydrocarbons increase in concentration with increasing maturity, while biomarkers decrease in concentration with maturity. This maturity dependent concentration variation plus the ubiquitous mixing of multiple oils in the reservoir is a key process that complicates the direct application of qualitative molecular marker ratio approaches to analysis of petroleum systems. We suggest an alternative maturity assessment approach using maturation calibrated curves of absolute concentrations of biomarkers and other alkanes in petroleum, coupled with selected aromatic hydrocarbon ratios to track the maturity/petroleum mass fraction relationships for a reservoired oil mixture in a more complex but realistic manner. Isoprenoid alkanes show less variation in concentration with maturity than other components and may be used as an internal reference point for mass fraction maturity and charge history assessment. Using component concentration data normalized to the concentration of the isoprenoid alkanes and calibrated using source rock analyses at different maturity levels from a single petroleum system (2WS), a simple mass balance model was constructed that allowed aggregate concentration data to be calculated for any mixture of oils produced in a prescribed oil charge history. In principle any charge history can be simulated using this approach and comparing the modelled and actual quantitative compositional profiles of crude oils allows differentiation of the more plausible and implausible oil charge histories for that particular reservoir. Clearly considerable refinement of this approach is needed but it appears that such a procedure has the potential, if developed further, to be a useful addition to the arsenal of petroleum geochemists and basin modelers. Knowing what a typical complete charge mass fraction maturity profile would look like for a given source rock type, enables the estimation of missing charge in the basin, allows the detection of complex multi-history charge scenarios, and provides a much more robust and complete data set for calibration of basin model charge history assessments. It also, with further development may be integrated into stochastic basin modelling approaches to study petroleum systems.

Formation processes of gas condensate reservoirs in the Baiyun Depression: Insights from geochemical analyses and basin modeling

The petroleum phase in a petroleum reservoir and the formation process of gas condensate reservoirs became a hotspot in petroleum geoscience. This study recovered the petroleum migration processes in the western sag of the Baiyun Depression based on the geochemical analyses and basin modeling to illustrate the formation processes of gas condensate reservoirs in the Baiyun Depression. The geochemical parameters of light oil and natural gases indicated that they originated from the Enping Formation. Basin modeling indicated that the Enping source rocks in the western sag were mature after 13.8 Ma. The petroleum migrations in the Enping and Zhuhai Formations were vertical, and the lateral migration occurred in the Lower Zhujiang Member. The petroleum generation–migration and temperature–pressure conditions mostly controlled the petroleum phase. The Enping source rocks produced some amount of oil in the oil window and generated considerable amount of gas later. Continuous gas charging increased the gas–oil ratio, and the light oil dissolved in the gas. With the increase in temperature and pressure, the oil reservoir eventually turned into a gas condensate reservoir. The gas condensate reservoir formation was mainly related to petroleum generation–migration–accumulation processes in the western sag. This study could contribute to petroleum exploration and development in the Baiyun Depression and some similar basins.

Genetic mechanism of transfer zones in rift basins: Insights from geomechanical models

Abstract A transfer zone is a kind of structure that is produced to conserve deformation of a fault structure on both sides. Increasing numbers of transfer zones are being identified in rift basins, which are areas of petroleum accumulation and potential exploration targets. This paper provides a numerical simulation method for the genesis and development of transfer zones based on geomechanical modeling. On the basis of three-dimensional (3-D) seismic interpretation, using the Tongcheng fault as an example, the fault activity parameter and fault activity intensity index were established to quantitatively characterize the difference in fault activity on the two sides of a transfer zone. A geomechanical model was developed for a transfer zone in a rift basin, and the structural characteristics and genetic mechanism of a convergent fault were studied using paleostress and strain numerical simulations. Affected by different movements of boundary faults and basement faults, the evolution of the Tongcheng fault can be divided into three stages: (1) during the Funing period, which was the main development period of compound transfer faults, the activity, stress, and strain of the fault blocks on either side of the Tongcheng fault were obviously different; (2) during the Dainan period, which was the development stage of inherited compound transfer faults, the northern part of the Tongcheng area underwent local compression, and the T3 anticline began to form; and (3) during the Sanduo period, the Tongcheng fault experienced right-lateral strike-slip activity, where the activity showed two stages of change, first increasing and then decreasing, and the Tongcheng fault anticline developed. The superposition of multiple complex tectonic movements produced a transfer zone that has both strike-slip and extensional fault properties. The geomechanical model in this paper provides important insights for analyzing the evolution of transfer zones in rift basins.

Organic matter characteristics and conventional oil potentials of shales from the Early Jurassic Datta Formation in the Upper Indus Basin, Northern Pakistan

This study deals with organic matter in the Early Jurassic Datta shale in the Upper Indus Basin, Pakistan. Organic geochemical and microscopic techniques were used to investigate organic matter input, environmental conditions of deposition as well as petroleum generation potential. The geochemical results suggest that the shales display mainly fair to good source rock generation potential, with poor petroleum generation potential in some samples. The HI varies between 32 and 519 mg HC/g TOC, with many of the samples appearing to be mainly Type II and mixed Type II-III kerogen, and thereby exhibiting the ability to generate both oil and gas. The dominance of such Type II kerogen in some samples is consistent with the high HI values (>300 mg HC/ g TOC) and high fluorescence alginite macerals. A section of the shale within the Datta Formation appears to be gas-prone, with HI values of less than 200 mg HC/g TOC. Biomarkers also indicate the presence of mixed organic matter of planktonic/bacterial and land plant input, which were deposited in a marine environment under relatively oxic conditions. The biomarker characteristics of the extracted shales correlate well with those of the oil from the Chanda Oilfield, indicating that the Datta shales are likely to be the effective source rock. This is supported by the thermal maturity, which ranges from moderate to peak-maturity, as indicated by vitrinite reflectance values of 0.69–0.82%, and the biomarker maturity indicators.

Oil generation model of the liptinite-rich coals: Palaeogene in the Xihu Sag, East China Sea Shelf Basin

Hydrocarbon generation from liptinite-rich coal is an important focus in petroleum geology as well as in coal geology. The confined pyrolysis experiment in gold tubes is an effective approach in assessing the hydrocarbon generation potential of coals. Xihu Sag is one of the most hydrocarbon-rich Cenozoic basins in the East China Sea Shelf Basin, and oil and gas are believed to be generated from Paleogene liptinite-rich coals. Coals from the Pinghu and Huagang formations of the Paleogene have a liptinite content mostly higher than 10%, and contain type II-III organic matter. The HImax values, H/C, and O/C ratios of these coals are in the range of 200–300 mg/g·TOC, 0.97 to 1.42, and 0.08 to 0.20, respectively. All these characteristics demonstrate good potential for these coals to generate oil. Experimental data show that the maximum cumulative yields of oil produced range from 122.74 to 154.09 mg/g·TOC, and the coals in the sag can also generate oil in their immature stage (Ro = 0.36%–0.5%) due to abundant resinite (mostly higher than 5%). To further assess the characteristics and processes of petroleum generation under geological conditions, we reconstructed the liquid hydrocarbon generation history of the coals in three structural units of Xihu Sag, i.e., the West Slope Belt, West Sub-sag, and Central Anticlinal Belt. For the coals in the Pinghu Formation, the West Slope Belt is a favorable oil-forming area, while the West Sub-sag and the Central Anticlinal Belt are less favorable oil-forming areas. For the coals in the Huagang Formation, the West Slope Belt is a favorable asphaltene (ΣC14+)-forming area, while the West Sub-sag and Central Anticlinal Belt are favorable light hydrocarbon (ΣC6-14)-forming areas. Results of this study will contribute to a better understanding of the characteristics and potential of oil generation from the liptinite-rich coals and are of significance for oil exploration in the Xihu Sag.

Evaluation of hydrocarbon potential of shale outcrops in the flanks of Anambra Basin

The research aim is to determine the organic productivity and hydrocarbon potential of the exposed shale lithology along Uzebba road and Bawa hills near Auchi, Southwest Nigeria.Twenty two (22) shale samples were acquired from the study area; twelve (12) from the outcropping section along Uzebba road, and the remaining ten (10) samples obtained from Bawa hills. The samples were then subjected to organic geochemical analysis using Total Organic Carbon (TOC) and Rock Eval Pyrolysis to evaluate the organic enrichment, organic quality and thermal maturity espectively.Total Organic Carbon (TOC) content of the twenty-two samples ranges from 3.42 – 4.88 wt. %, affirming a high organic enrichment. Shale samples from Uzebba segment and Bawa hills falls within the Type I and Type II Kerogen class respectively. The former is indicative of immature – sub mature organic matter with no hydrocarbon formation prospect whilst the latter exhibits great hydrocarbon (oil) generation potential Thermal maturation assessment for both samples apparently ranges from immature to mature organic matter. From the Rock-Eval pyrolysis result, all the twenty-two (22) samples were confirmed to be organically enriched. However, the type I kerogen of Bawa at favourable geothermal gradient can potentially serve as a suitable source rock for petroleum generation.

Maturation and migration processes in intact source rock micro plugs induced by chemical and thermal treatment: A new approach combining Rock-Eval pyrolysis and organic petrography

This study proposes a new approach to investigate hydrocarbon generation and migration processes in petroleum source rocks under laboratory conditions. For the first time, programmed open-system pyrolysis using a Rock-Eval 6 instrument is applied on small, polished source rock plugs to induce changes in the type and distribution of solid bitumen, which are qualitatively investigated by means of organic petrography before and after different pyrolysis experiments. This approach allows us to directly visualize the evidence of solid bitumen (SB) formation and distribution after the following treatments: (1) thermal extraction at 300 °C for 3 min, (2) chemical extraction of the surface using dichloromethane (DCM), and subsequently (3) artificial maturation by applying the standard procedure of Rock-Eval programmed pyrolysis up to a temperature of about 400 to 500 °C (depending on the initial thermal maturity of the sample). After each step, the surface of the treated micro plugs was digitally scanned to allow a comparison of specific areas of interest before and after the respective treatments and alterations. For this study, core samples of the Eagle Ford Shale Formation are used, which are suitable for such investigation, as the Eagle Ford Shale exhibits a variety of different initial thermal maturities from immature to overmature. Furthermore, the presence of large intraparticle porosities provides suitable voids where changes in SB distribution can easily be observed. After the thermal extraction, the volume of observed SB in the early- and moderately mature samples slightly increased, while most of the thermally mobilized bitumen from inside the plug was evaporated and thus lost from the sample. The initial solid bitumen was not or hardly affected by thermal extraction at 300 °C for 3 min, i.e. it was thermally stable at this temperature. Solid bitumen reflectance was slightly higher than in the initial sample showing a minor maturation. In contrast to thermal extraction, solid bitumen in the early mature samples was almost completely dissolved after DCM treatment. These petrographic observations on micro plugs are in agreement with the pyrolysis results of powdered fractions, where the initial Rock-Eval S1 and to a much lesser extent also the S2 signal decreases after the chemical extraction in DCM. While the SB in early mature sample was almost entirely dissolved by DCM, only about half of it is was dissolved in the moderately mature sample showing more mature and more stable SB. After the artificial maturation, the volume of SB in early- as well as in moderately mature samples clearly increased within the intraparticle pores, indicating presence of new SB due to bitumen migration from the deeper part of the micro plug to the surface. In contrast, SB in initially overmature sample is mainly present as thermally-highly stable pyrobitumen, indicated by no change in the SB distribution after chemical and thermal treatments representing a stable type of SB at the very end of petroleum generation.

Geochemical characteristics and origins of biodegraded oils in the Bongor Basin (Chad) and their implications for petroleum exploration

The Bongor Basin is a typical lacustrine passive-rifted basin situated in the West and Central African Rift System (WCARS). It has experienced two phases of tectonic inversion and features a complex process of petroleum generation and accumulation. A total of 41 crude oil samples from the basin were geochemically analyzed to investigate their compositions of molecular markers. The results show that the oils have similar origins and are likely to belong to the same oil population. However, there are significant differences in geochemical characteristics and physical properties, caused by the secondary alteration. The relative contents and distribution patterns of normal alkanes and acyclic isoprenoids indicate that some of the oils have suffered biodegradation to varying degrees. The samples can be divided into three categories according to their relative degrees of degradation: normal oil, slightly biodegraded oil (PM 1–3), and severely biodegraded oil (PM 5–7). The burial depth of oil reservoirs in this area is the predominant factor impacting on the level of biodegradation. Crude oils in reservoirs with burial depths of less than 800 m are all severely biodegraded, while oils in reservoirs with burial depths greater than 1300 m have experienced no evident biodegradation. In reservoirs with burial depths between 800 m and 1300 m, the biodegradation degrees vary from normal to severely biodegraded. Oil reservoirs with burial depths less than 1300 m and adjacent to major faults are readily subject to biodegradation, while reservoirs with similar burial depths, but a certain distance away from major faults, have suffered no evident biodegradation. Moreover, if primary reservoirs have been modified by tectonic activity after accumulation, the crude oils are more likely to be biodegraded. Faulted anticline traps may create more favorable geological conditions for preservation of crude oil than reverse extrusion anticline reservoirs. This study may provide practical guidance for the assessment and prediction of oil quality in future oil exploration.

Genesis and preservation of the giant ultradeep Hadexun petroleum accumulation in the Tarim Basin, China

Reservoired liquid petroleum has limited potential to be preserved under high temperature conditions due to thermal cracking and potentially thermochemical sulfate reduction, and thus exploration targets in ultradeep strata are mainly gas and condensate gas. However, a giant ultradeep liquid petroleum accumulation, with an average depth of >6500 m, was discovered recently in the Hadexun area, Tarim Basin. In this study, integrated geochemical analyses were conducted on the black oil samples from the Hadexun area. Intact terpanes and steranes and low concentration of diamondoids were detected, indicating that these oils were generated at peak oil window and were barely altered by secondary geochemical process (thermal cracking or others) despite their depth. The associated wet gas with light isotopic profiles was classified as mature oil-derived gas co-generated with the oil. Petroleum accumulation analyses suggested that the favorable carbonate reservoir bodies in the Middle Ordovician Yijianfang Formation were attributed to karstification and weathering, and mainly distributed along the major strike-slip fault belts. Together with the thick mudstones in the overlying Upper Ordovician Sangtamu Formation, they formed a favorable reservoir-seal assemblage in the Hadexun area. Massive volumes of liquid petroleum were generated and expelled from the Lower Cambrian black shales in the Late Hercynian and migrated into the Ordovician carbonate reservoirs through the strike-slip fault system, and subsequently were exposed to stable tectonic conditions. Due to the rapid subsidence since the Neogene, insufficient temperature-time exposure eliminated the impact of thermal cracking; therefore, the petroleum accumulation was preserved in the liquid phase, and further indicates that huge petroleum resource potential remains in ultradeep strata in the Tarim Basin. • Oil/gas sourced from the Cambrian shales were barely altered by geochemical process. • Insufficient compensation of temperature and time led to the preservation of the ultradeep oil. • Oil/gas was preferentially enriched in favorable carbonate reservoir bodies along faults. • Liquid petroleum and condensate/gas are the main targets in Ordovician and Cambrian assemblages, respectively.

Geochemistry and source of crude oils in the Wensu uplift, Tarim Basin, NW China

The Wensu uplift, to the northwest of the Tarim Basin, is located at the intersection of the marine Awati basin and the continental Kuche foreland basin. The origin and accumulation of hydrocarbons are complex processes in the Wensu uplift. The XWD 1 and 2 wells, drilled in the Wensu uplift in 2017, produced high-yield commercial oil flows from Neogene strata, thus realizing the first major breakthrough in the region's 50 years of oil and gas exploration. This discovery invited significant attention from the research community for shallow hydrocarbon accumulations along the margins of the Tarim Basin. This study focuses on the Neogene hydrocarbons of the Wensu uplift along with their geochemical characteristics and origin. We propose a hydrocarbon accumulation model, reconstructed by combining geology and geochemistry. The results show that crude oils from the Wensu uplift display typical lacustrine characteristics: 1) higher Pr/Ph values (1.68–2.04, average 2.33) that are indicative of an oxidizing sedimentary environment for the source rock; 2) higher content of rearranged steranes, C29Ts, and C30 diasteranes and lower DBT/P value (0.09–0.11), indicating that the source rock is shale with a high content of clay minerals; and 3) lower sterane/hopane ratios (0.14–0.15) indicating high inputs of bacteria and microorganisms. The above characteristics are distinct from the adjacent marine crude oils which feature relatively lower ratios of Pr/Ph (1.27–1.37) and higher ratios of DBT/P (0.62–0.82) and steranes/hopanes (0.87–0.90). The oil-oil and oil-rock correlations conducted using hydrocarbon biomarkers and carbon isotope ratios show that the oils in Wensu uplift contain contributions from the lacustrine source rocks of the Jurassic Qiakemake (J2q) and Triassic Huangshanjie (T3h) formations of the eastern Wushi–Baicheng sag, suggesting that the Wensu uplift oils have a mixed origin. The age of stratigraphic traps in the Wensu uplift coincides with that of hydrocarbon expulsion peak and the hydrocarbons accumulated along the slope by long-distance migration. The results of this study aim to serve as an important guide for further studies on petroleum accumulation mechanisms and shallow hydrocarbon explorations in basin margins devoid of local hydrocarbon source rocks.

Influence of Quaternary glaciations on subsurface temperatures, pore pressures, rock properties and petroleum systems in the onshore northeastern Netherlands

AbstractPleistocene glacial stages were implemented into a 3D basin and petroleum systems model of the northeastern Netherlands to address the influence of low surface temperatures and the mechanical loading of ice sheets on the subsurface. Two ice sheet thickness scenarios were used based on published data. Overall, Quaternary glacial stages have a substantial impact on the temperature and pressure distribution in the subsurface. Subsurface temperatures are significantly reduced during glacial stages, leading to lowered present-day temperatures and a low geothermal gradient in the shallow subsurface. In deeply buried sedimentary formations, pressures build up with every glacial advance resulting in overpressures at the present day. Glacial stages do not directly influence the petroleum generation of petroleum source rocks in the area, but high pressures during loading might have impacted petroleum expulsion of the early mature Coevorden Formation. Hydrocarbon accumulations in the Lower Saxony Basin were simulated to investigate the possible effects of mechanical ice loading and unloading on hydrocarbon migration. A loss of Coevorden Formation-sourced hydrocarbons to the surface was calculated in the Lower Saxony Basin during the glacial stages, indicating an influence of glacial loading on the Mesozoic petroleum system.

Evaluation of Thermal Maturation of Hydrocarbon Potential Source Rocks From Kombe-Kompina-Missole Areas of the Douala Sub- Basin Using Spore Color Variation Technique

The Douala sub-Basin is well-known as a highly prospective basin for petroleum generation. The depletion of some oil Wells originally discovered in Cameroon calls for further investigation on the maturity of potential source rocks so as to discover more oil fields. The current methods used by many researchers for evaluating the thermal maturity of potential source rocks are mostly the geochemical techniques which are pretty expensive. Thus, this study was set out to evaluate thermal maturation of potential source rocks exposed in the Kombe-Kompina-Missole areas of the Douala Sub-Basin through the use of spore color variation as an alternative cheaper method of determination with a higher precision than the former. This work had three specific objectives; to carry out loggings, to obtain and identify sporomorphs, to determine the extent of thermal alteration of sporomorphs present in the samples through microscopic examination of spore and pollen color variation. A total number of fifteen samples obtained from the sedimentary sequences encountered in the studied area were sent for laboratory analysis. The results obtained from palynological analysis showed that color index of organic matter at Kombe and Kompina ranges from 2 to 2/3 which are immature to early mature source rocks with kerogen type II, III and IV. While for Missole, color index ranges from 2/3 to 3 indicating early maturity to mature source rocks with kerogen type II. Facies identified from lithofacies analysis included: sandstones, shales, mudstones, siltstones, conglomerates. Therefore, palynological methods based on spore color variationis an efficient and cheaper method of determining thermal maturity.

Source rock pyrolysis and bulk kinetic modelling of Miocene sedimentary sequences in southeastern Sabah, Malaysia: The variability of thermal maturity to oil-gas producing kerogen

The study reports a new organic geochemical evaluation for a petroleum source rock in the Southeastern (SE) Sabah basin. The analyses focus on Kalabakan, Tanjong, and Kapilit Formation deposited in the deltaic-shallow marine environment stratigraphically from the Early to Late Miocene sequences. The basin sediments are part of the hydrocarbon prolific Tarakan basin, extending from the northernmost of Kalimantan Indonesia to the southeastern Sabah (mainly onshore area). The hydrocarbon generation of Kapilit and Tanjong Formation pinnacles the Total Organic Carbon (TOC) contents that range from 0.62 to 81.97 wt% and 0.97–92.96 wt% respectively. The dominant black shale in Kalabakan Formation has lower TOC content between 0.50 and 1.82 wt%. The results in the Rock-Eval S2 of Kapilit (0.31–351.61 mg HC/g rock) and Tanjong Formation (3.32–239.78 mg HC/g rock) have excellent source rock potential compared to the Kalabakan Formation (0.12–1.19 mg C/g rock) with fair to good source rock potential. All three formations give a wide maturity range of vitrinite reflectance (VRo) and Tmax values, from immature to over-mature stage. Stratigraphically from youngest to oldest Miocene sequences, the Tmax increases with increasing VRo values. The dispersion of organic matter that requires high maturity and overburden of thick upper succession over Kalabakan Formation reflects a higher maturity stage than the Tanjong and Kapilit Formations. Pyrolysis results in Kapilit, Tanjong, and Kalabakan Formation has HI values to varies between 50 and 498 mg HC/g, 157–367 mg HC/g and 14–110 mg HC/g TOC respectively. The binary plot of HI versus Tmax supported by Py-GC pyrolysis marks that the Kapilit source rock is dominated by Type II-III kerogen, potentially generating immature to mature oil and gas prone. Tanjong Formation portrays a mature to late mature stage of Type III kerogen with a minor Type II kerogen capable of producing mixing of oil and gas prone, with mainly gas. The Kalabakan Formation shows a post-mature Type III and IV kerogen that generates gas or barren source rock. In terms of bulk kinetic evaluation, both Kapilit and Tanjong Formation are derived from heterogeneous organic matter. The projected petroleum temperature varies substantially due to the compositional variation. The onset of bulk petroleum generation in the Kapilit and Tanjong Formation occur at 112 °C - 128 °C and 127 °C - 142 °C respectively. The results are consistent with the maturity generated where the Tanjong has higher thermal maturity than Kapilit Formation due to stable aromatic Type III kerogen. Generally, all samples show great variability in thermal maturity and hydrocarbon generation potential, which that be influenced by the tectonism and development of sediments in the basin. The Early Miocene source rock yields post mature gas prone and continues to generate hydrocarbon that consists of mature oil and gas prone from younger source rocks.

Velocity Structure Revealing a Likely Mud Volcano off the Dongsha Island, the Northern South China Sea

The Dongsha Island (DS) is located in the mid-northern South China Sea continental margin. The waters around it are underlain by the Chaoshan Depression, a relict Mesozoic sedimentary basin, blanketed by thin Cenozoic sediments but populated with numerous submarine hills with yet less-known nature. A large hill, H110, 300 m high, 10 km wide, appearing in the southeast to the Dongsha Island, is crossed by an ocean bottom seismic and multiple channel seismic surveying lines. The first arrival tomography, using ocean bottom seismic data, showed two obvious phenomena below it: (1) a low-velocity (3.3 to 4 km/s) zone, with size of 20 × 3 km2, centering at ~4.5 km depth and (2) an underlying high-velocity (5.5 to 6.3 km/s) zone of comparable size at ~7 km depth. MCS profiles show much-fragmented Cenozoic sequences, covering a wide chaotic reflection zone within the Mesozoic strata below hill H110. The low-velocity zone corresponds to the chaotic reflection zone and can be interpreted as of highly-fractured and fluid-rich Mesozoic layers. Samples dredged from H110 comprised of illite-bearing authigenic carbonate nodules and rich, deep-water organisms are indicative of hydrocarbon seepage from deep source. Therefore, H110 can be inferred as a mud volcano. The high-velocity zone is interpreted as of magma intrusion, considering that young magmatism was found enhanced over the southern CSD. Furthermore, the origin of H110 can be speculated as thermodynamically driven, i.e., magma from the depths intrudes into the thick Mesozoic strata and promotes petroleum generation, thus, driving mud volcanism. Mud volcanism at H110 and the occurrence of a low-velocity zone below it likely indicates the existence of Mesozoic hydrocarbon reservoir, which is in favor of the petroleum exploration.

Tracing fluid evolution in sedimentary basins with calcite geochemical, isotopic and U-Pb geochronological data: Implications for petroleum and mineral resource accumulation in the Nanpanjiang Basin, South China

AbstractFluid migration in sedimentary basins enable mass and energy transport and play critical roles in geochemical and geodynamical evolution of sedimentary basins. Moreover, reconstructing sedimentary basin fluid evolution from the geological record aids in constraining the evolution of associated petroleum and mineralization systems. As a relict of fluid flow activity, calcite is often a record of fluid flow and therefore can be used to characterize the fluids responsible for its precipitation.Here we study the Nanpanjiang Basin in South China where petroleum reservoirs and Carlin-type gold deposits spatially coincide. Through in situ U-Pb dating and geochemical analysis (87Sr/86Sr, δ18OVienna standard mean ocean water, δ13CVienna Peedee belemnite, rare earth elements) of calcite, this work constrains the key times related to petroleum migration/accumulation and Carlin-type gold mineralization, defines the basin fluid evolution, and proposes a genetic model for petroleum accumulation and gold mineralization within the Nanpanjiang Basin. The U-Pb age (ca. 241.4 Ma) for the gray/black calcite related to bitumen indicates the petroleum migration/accumulation occurred during the Triassic. The U-Pb date (ca. 106–121 Ma) of the white calcite associated with the gold-bearing pyrite, realgar, and fluorite record the lower timing limit of the Carlin-type gold systems. The geochemical data suggest both calcite types are cogenetic but suffered complex evolution with the gray/black calcite precipitating under low temperatures related to the continuous basin burial and the white calcite affected by post formation alteration related to both hydrothermal and meteoric fluids. Combined with the regional tectonic history, the Early Triassic petroleum migration/accumulation and the Early Cretaceous secondary Carlin-type gold mineralization events are considered to be related to the collision between the Indo-China and South China blocks, and the subduction between the Paleo-Pacific and Eurasian plates, respectively.

Hydrothermal synthesis of long-chain hydrocarbons up to C24 with NaHCO3-assisted stabilizing cobalt

Abiotic CO2 reduction on transition metal minerals has been proposed to account for the synthesis of organic compounds in alkaline hydrothermal systems, but this reaction lacks experimental support, as only short-chain hydrocarbons (<C5) have been synthesized in artificial simulation. This presents a question: What particular hydrothermal conditions favor long-chain hydrocarbon synthesis? Here, we demonstrate the hydrothermal bicarbonate reduction at ∼300 °C and 30 MPa into long-chain hydrocarbons using iron (Fe) and cobalt (Co) metals as catalysts. We found the Co0 promoter responsible for synthesizing long-chain hydrocarbons to be extraordinarily stable when coupled with Fe-OH formation. Under these hydrothermal conditions, the traditional water-induced deactivation of Co is inhibited by bicarbonate-assisted CoOx reduction, leading to honeycomb-native Co nanosheets generated in situ as a new motif. The Fe-OH formation, confirmed by operando infrared spectroscopy, enhances CO adsorption on Co, thereby favoring further reduction to long-chain hydrocarbons (up to C24). These results not only advance theories for an abiogenic origin for some petroleum accumulations and the hydrothermal hypothesis of the emergence of life but also introduce an approach for synthesizing long-chain hydrocarbons by nonnoble metal catalysts for artificial CO2 utilization.

Geochemical rationalisation for the variable oil quality in the Orcutt reservoir, California, USA

The relationship between fluid physical properties and hydrocarbon compositions was investigated on a suite of eleven heavy oil samples from the Orcutt Field, onshore Santa Maria Basin in California. The physical properties of oils display a considerable range across the reservoir, with viscosity varying from 46.3 to 611,150 centipoises at 20 °C and API gravity from 16.3 to 25°. Not surprisingly, the molecular composition of the Orcutt Field oils is also highly variable.Present-day fluid physical properties in the field are determined by the mixing of multiple petroleum charges. The bulk of the oil volume in place was generated by source rocks of the Monterey Formation in the early oil window stage of petroleum generation. The mixing of biodegraded and non-biodegraded oils indicates at least two oil charge events, punctuated by episodes of biodegradation. Oil viscosity decreases towards the Orcutt Frontal fault and Solomon Hills fault, which bound the Orcutt anticlinal structure to the northeast. These faults appear to be conduits for a separate diamondoid-rich light oil or condensate charge responsible for localised improvements in oil viscosity towards the NE and in the crest of the structure.Data from this study show the profound impact of charge mixing and in-reservoir alteration on physical properties of oils within a single accumulation.

Influence of sulfate on the generation of bitumen components from kerogen decomposition during catagenesis

High-quality source rocks in saline lacustrine or marine sedimentary environments often show early peak petroleum generation and enhanced hydrocarbon yields, which have conventionally been attributed to organosulfur-enhanced thermal decomposition of kerogen. However, there is increasing awareness that the coexisting inorganic salts, particularly sulfates, might also contribute to the acceleration of petroleum generation. In this study, we investigated the influence of sulfates on the thermal decomposition of kerogen sampled from the Pingliang Formation in the Ordos Basin. Our results demonstrate that the kerogen samples mixed with sulfate generate more hydrocarbons with a lower peak production temperature than their sulfate-free counterparts. Detailed chemical analysis revealed that the presence of sulfates significantly facilitated the generation of resins and asphaltenes at temperatures below 350 °C, corresponding in our simulations to the early stage of petroleum generation (Easy%Ro < 1.0%). We hypothesize that sulfates can promote the fragmentation of kerogen via direct thermochemical oxidation into a complex mixture of bitumen components that consist mostly of compounds typically encountered in the classical resin and asphaltene fractions. The findings reveal a new reaction paradigm between sulfates and organic macromolecules that could offer useful guidance in the exploration for low-maturity oils.

Organic geochemistry, oil-source rock, and oil-oil correlation study in a major oilfield in the Middle East

In this study several major source rocks: Kazhdumi, Pabdeh, and Gurpi formations, along with crude oils from the Asmari and Bangestan reservoirs in the Gachsaran oilfield, southwestern Iran, were investigated from the organic geochemistry point of view. Results indicate that the Kazhdumi and Pabdeh formations have excellent generation potential and are mature and immature source rocks, respectively. In contrast, the Gurpi Formation has lower petroleum generation potential. The organic matter in the Kazhdumi and Pabdeh formations in the neighboring synclines within the Gachsaran oilfield is in the late and peak oil generation stages, respectively. SARA composition by Liquid Chromatography performed on four crude oils produced from these source rocks suggest a paraffinic-naphthenic composition. The source rocks had carbonate and shale lithology. Distinct biomarkers point to an open marine environment characterized by marine kerogen Type II and mixed Types II/III deposited under anoxic-suboxic depositional conditions, although. The presence of relatively high amounts of oleanane in the oils points to contribution from a terrigenous source. Based on biomarkers, the four oils exhibit similar thermal maturity, which is equivalent to the primary stage of oil generation. The star diagrams of various normal alkanes and biomarker ratios show that the four crude oil have high similarities, which suggests a single source origin. Nonetheless, utilizing different ML methods of K-means Clustering, Fuzzy C-means clustering (FCM), Comptlayar Neural Network, Construction of agglomerative clusters, and the obtained dendrogram all suggest that there are two oil families in the Gachsaran oil field. Furthermore, geochemical parameters including specific biomarkers denote the contribution of the Kazhdumi and Pabdeh formations in the Gachsaran oil field whereby charges of mixed origins at different reservoir horizons of Asmari and Bangestan can be identified. Ultimately, two scenarios for the presence of oleanane in Bangestan reservoir are envisaged: 1) connectivity of the Asmari and Bangestan reservoirs as a result of natural fracturing, and 2) emplacement of the Pabdeh Formation near the vicinity of the Bangestan reservoir as a result of thrust faulting. Overall, this study demonstrated that integration of data analytics (ML) methods with conventional geochemical techniques can precisely delineate the correlation between the generated oil and the source rocks. • Geochemical analysis performed on two rarely studied major source rocks in Middle East: kazhdumi and Pabdeh Formations. • Several machine learning (ML) algorithms were implemented to identify existing oil families from these two source rocks. • These two oil families were also confirmed by detection of the Oleanane biomarker in separated oil groups.

PhaseKinetics for assessing the compositional evolution of petroleum generated from the early to Late Miocene source rock, Belait Formation, Brunei-Muara district, Brunei Darussalam

The Early to Late Miocene Belait Formation in Brunei-Muara district has been investigated using the PhaseKinetic approach for compositional petroleum generation kinetics. The source rock characteristics of the selected coal and coaly shale samples indicate kerogen type III-II and type III with moderate HI recorded in the range of 156–258 mg HC/g TOC. The Rock Eval pyrolysis data also show immature organic matter with maximum recorded Tmax values of 415 °C. Pyrolysis gas chromatography (PyGC) reflects that the source rocks generated petroleum grading from paraffinic-naphthenic-aromatic (P–N-A) high wax to gas and condensate, which can be interpreted as heterogeneous kerogen derived from terrigenous higher land plant material. The main activation energies range of two selected coal samples (S24 and S27) are located at 49–52 kcal/mol accounting each for only 15% of the total bulk reaction. Assuming a 3 °C/My geologic heating rate, calculated onset temperatures for the generated hydrocarbon at transformation ration, TR = 10% were 105–120 °C for the two samples. The end of hydrocarbon generation at approximately TR = 95% is expected to occur at temperatures around 170 °C and above. MSSV pyrolysis gas chromatography affirms the existence of high wax paraffinic kerogen type–III–II with some marine input for one end member sample (S24). The 4-component compositional kinetic model indicates that the maximum generation of different petroleum components of sample S24 is predicted at lower values of temperature and vitrinite reflectance if compared with sample S27. The other end member of sample (S27) is more typically humic coal-like with type-III kerogen generating mostly gas and condensate.