Hydrocarbon Accumulation Research Articles

LITHO-STRATIGRAPHIC FEATURES OF THE LOWER CRETACEOUS DEPOSITS OF THE SKYBA AND DUKLA-CHORNOGORA NAPPES OF THE UKRAINIAN CARPATHIANS AND PROSPECTS FOR THEIR OIL AND GAS POTENTIAL

Lower Cretaceous sediments are widespread within the Skybа and Dukla-Chornorgora Nappes (Spas and Shypot Formations) over a considerable area. These deposits contain sandstones that can be industrial reservoirs for hydrocarbons. Such sandstones are described both on the surface and identified in deep wells. Thick sandy strata in the middle part of the Spas and Shypot formations formed as deposits of gravity flows at the second level of avalanche sedimentation, at the foot of the continental slope of the northern continental margin of the Tethys Ocean. Their formation is correlated with global regression in Aptian time. Porous sandstones of the Spas formations are present on the surface in the areas of the villages of Tershiv and Busovysko. They sometimes form bundles up to 60 m thick. They are exposed in the Oryv and Berehyv Skybas by deep wells 1-Lugy, 1-Shevchenko, and 4-Maksymivka. During the drilling of the 1-Shevchenko well from a depth of 6,900 meters, a film of oil and gas continuously flowed into the drilling mud. According to the results of industrial and geophysical studies, the section of the Spas formations of the second (lower) scale in the interval of 6,940–7,520 m was recognized as the most promising in terms of oil and gas potential. Two promising objects in the intervals of 7020–7070 and 6945–6985 m were identified, the oil and gas saturation coefficients of which are 65–70%. Similar sandstones are noted in the Hoverla sub-Nappe of the Dukla-Chornogora Nappe along the Balzatul River and its tributaries (Bila Tysa River Basin) as part of the Shypot Formation. Sandstones with an open porosity of 8–12 % were identified in the 1-Hrynyava and 1-Semakiv wells in the deposits of the Shypot Formation of the Skupiv sub-Nappe according to the results of industrial-geophysical research. When testing them in the 1-Semakiv well, from the total interval of 473–569 m, they received inflows of combustible gas and light oil with flow rates of 3,000 m3/day and 2.64 m3/day, respectively. The analyzed materials testify to the prospects of the Spas and Shypot formations in relation to the discovery of industrial accumulations of hydrocarbons.

3D static modeling and sequence stratigraphy using well logs and seismic data: An example of Abu Roash G member in Bahga oilfield

This research uses both three-dimensional (3D) modeling and geologic well control to piece back together the architectural parts of the Late Cretaceous formations. The goal is to figure out the sizes, directions, locations, and controls of the layers of the fluvial sandstone reservoirs. Sequence stratigraphy is essential for 3D reservoir modeling and petroleum geology understanding in the Bahga oilfield. The purpose of this work is to create a static model that shows the layers and facies distribution in the reservoir interval. We will use data from nine well logs and 22 seismic lines calibrated by the Abu Roash G Member reservoir core intervals to accomplish this. The petrophysical study discovered three parts in the Abu Roash G Member reservoir rock: channel fill that is affected by tides, channel fill that is dominated by tides (intertidal sands), and channel top with lenticular bedded sandstone. The model's findings point to the existence of an NNW-oriented sand body, which could be a prime location to produce hydrocarbons. The original oil in place (OOIP) is about 3,438,279 Stock Tank Barrels (STB), and the oil reserve reaches up to 1,031,484 (STB). Sequence stratigraphic analysis using seismic and well log information (SB) reveals that the Upper Cretaceous AR/G reservoir of the Bahga field is characterized by third- and fourth-order stratigraphic sequences, which are constrained by three Maximum Flooding Surfaces (MFS) and two Sequence Boundaries. The integration of the derived geological model and sequence stratigraphic results can lower future extraction risk by identifying the locations and trends of the geologic facies with the necessary petrophysical properties for the hydrocarbon accumulations.

TO THE 60TH ANNIVERSARY OF THE DEPARTMENT OF EARTH SCIENCES OF THE NATIONAL ACADEMY OF SCIENCES OF UKRAINE

In the second part of the article, the main historical events in terms of dates, facts and personalities of the formation and development of the institutions of the Department of Earth and Space Sciences of the Academy of Sciences of the Ukrainian SSR from its foundation in 1963 to Ukraine’s independence in 1991 are listed in chronological order. The course of events related to name changes is given: Department of Earth and Space Sciences (1963–1972), Department of Earth Sciences (1972–1980), Department of Geology, Geophysics and Geochemistry (1980–1983) and Department of Earth Sciences (1983–1991). Considerable attention is paid to the significant contribution of the specialists of the Department of Earth Sciences of the Academy of Sciences of the Ukrainian SSR in eliminating the consequences of the largest technogenic and environmental disaster that occurred on April 26, 1986 at the Chornobyl nuclear power plant. It is considered the most important achievements of the institutions of the Department of Earth Sciences of the Academy of Sciences of the Ukrainian SSR in the period of formation and active development. In particular, scientific substantiation of the search for industrial oil and gas accumulations in the crystalline foundation of the sedimentary basins of Ukraine, volcanic and volcanogenic-sedimentary rocks of Transcarpathia and the Dnipro region, in the zones of active water exchange on the regional monoclines of Precarpathia, the Black Sea region. The doctrine of the formation of deep fault structures has been developed, and a technique has been developed for forecasting of combined traps of hydrocarbon accumulations in deep-seated Devonian and Carboniferous horizons of the Dnipro-Donetsk Basin. Significant results were obtained regarding the geological structure of the earth’s crust and the upper mantle of the lithosphere within the framework of international projects during regional seismic research within limits of Ukraine, Southeast Europe and India. The general regularities of the structure are established for various geostructures: shields, platforms, depressions, transition zones from continents to oceans, deep-sea depressions, structures of the ocean floor. The theoretical principles, methods and technical means of remote ocean research using artificial Earth satellites were developed, and the country’s first system for collecting, transmitting and processing information about the ocean’s physical fields was created. This is a kind of report of the most significant events and facts from the life of the Department of Earth Sciences of the National Academy of Sciences of Ukraine and personal information and scientific achievements of the members of the Academy elected in the considered period.

Melanin-mediated accumulation of polycyclic aromatic hydrocarbons in human hair: Insights from biomonitoring and cell exposure studies

While human hair is widely used to monitor micro-organic contaminants (MOCs), their incorporation mechanisms are poorly understood. Melanin, known to facilitate the accumulation of drugs in hair, hasn’t been studied in the field of MOCs. Here, polycyclic aromatic hydrocarbons (PAHs), a class of priority MOCs, were investigated through hair biomonitoring as well as cell exposure experiments. PAH concentrations and melanin contents were measured in black and white hairs from the same individual. The results showed that five dominant PAHs (phenanthrene, fluoranthene, pyrene, benzo[a]anthracene and chrysene) in black hair (0.66 ng/g – 35.1 ng/g) were significantly higher than those in white hair (0.52 ng/g – 29.6 ng/g). Melanin contents in black hair (14.9 – 48.9 ng/g) were markedly higher than in white hair (0.35 – 2.15 ng/g) and were correlated to PAH concentrations, hinting melanin-mediated accumulation of PAHs in hair. The in vitro experiment using murine melanoma cells demonstrates that PAH levels in cells were affected by melanin, suggesting the affinity of melanin to PAHs. Both biomonitoring and cell exposure experiment implicate the pivotal role of melanin in PAH accumulation in hair. Therefore, to ensure the accuracy of hair biomonitoring for MOCs, attention must be paid to the melanin content uniformity.

Novel insights about petroleum systems from source and reservoir rock characterization, Cretaceous Deposits, Babouri-Figuil Basin, Northern Cameroon

The Babouri-Figuil Basin (BFB) is a frontier basin for petroleum in Cameroon. It belongs to the series of Cretaceous rift basins of the West and Central Rift System (WCARS), the origin of which is related to the opening of the South Atlantic. Within the same rift system, commercial hydrocarbon accumulations have been discovered in Chad, Sudan, Niger and, more recently, in Nigeria (Gongola Basin). The study of the geology of the BFB just recently received considerable attention, mainly because of its presumed hydrocarbon potential. In the pursuit of researching possible petroleum systems in the BFB, the current study provides a first look into the characterization of source and reservoir rock and its integration into a 2D lithostratigraphic model. The study was solely based on outcrop samples. Black shale and massive claystone are good to excellent hydrocarbon source rocks [e.g., up to 38 wt% total organic carbon (TOC), up to 943 mg/g hydrogen index, up to 85 m thickness, up to 20–30 km lateral extension], with moderate to high values of extractable organic matter (e.g., >10,000 ppm). Calcareous claystone, on the other hand, are poor source rocks [e.g., <0.20 wt% TOC]. The samples are thermally immature, except for those located close to volcanic intrusion at Golombe that have reached the threshold for oil generation (Tmax >435 °C, production index >0.1). The petrographic analysis of sandstone revealed that they are fine-grained to coarse-grained, poorly to moderately sorted, texturally and compositionally immature to submature, subarkosic to arkosic arenites. The main diagenetic processes that affected sandstones are as follows: moderate to intense compaction characterized by the development of long, concavo-convex, and sutured contacts between grains; cementation through calcite, iron oxide, and quartz cements; alteration of mica and feldspar grains; partial to complete dissolution of feldspar, mica, amphibole grains, and calcite cement; and the replacement of feldspar and mica grains by clay minerals. Alteration and dissolution increase the porosity of sandstone through the creation of secondary pores. However, mechanical compaction through the development of a pseudomatrix and cementation as pore-filling materials have significantly reduced the quality of sandstone beds as conventional petroleum reservoirs. Hence, the best reservoir-quality sandstones in the basin are generally located in the upper portion of the basin in terms of its lithostratigraphic model. They are the cleanest sandstones with the smallest amount of cement and the lowest ductile grain content (pseudomatrix), with a thickness that varies from 3 m to 120 m and a lateral extension of 20 km. The lithostratigraphic model of the basin is characterized by an extensive lacustrine environment that provided a thick sequence of organic-rich formations; sand deposited as extensive reservoirs sandwiched between shale/claystone beds; the development of stratigraphic traps through lateral facies change; and the widespread deposition of lacustrine and floodplain claystone that provide regional seals. The similarities between the Babouri-Figuil Basin and proven petroleum systems in other WCARS rift basins suggest that the basin may host at least one petroleum system where actively generating source rocks are present.

Reservoir Characterization of Alluvial Glutenite in the Guantao Formation, Bohai Bay Basin, East China

Alluvial glutenite reservoirs have obviously stronger heterogeneous and more complex control factors than sandstone reservoirs. Taking the Binxian Uplift area in the Boahi Bay Basin as an example, the aim of this study is to clarify the characteristics and control factors of the alluvial glutenite reservoir quality and the influence of reservoir properties on hydrocarbon accumulation. Pore types in the study area mainly include residual intergranular pores, intergranular dissolved pores, intragranular dissolved pores, and mold pores. The residual intergranular pores and intergranular dissolved pores are the main pore types. Most samples have porosity greater than 15% and permeability is mainly concentrated between 50 mD and 500 mD. It is shown that lithology type, microfacies, and diagenesis have significant impact on the reservoir quality. The reservoir qualities of very fine sandstone and fine sandstone are better than those of conglomerate and gravel-bearing sandstone. Instead of grain size, sorting affects the alluvial glutenite reservoir quality significantly. Oil-bearing samples commonly have sorting coefficient less than 2 while non-oil-bearing samples have sorting coefficient larger than 2. There are significant differences in reservoir physical properties of different sedimentary microfacies. The stream flow in mid-alluvial fan (SFMA) and braided channels outside alluvial fans (BCOA) have relatively weaker compaction and better reservoir quality than the overflow sand body (OFSB) and debris-flow in proximal alluvial fan (DFPA). Calcite cementation, the main cement in the study area, commonly developed at the base of SFMA and BCOA and near the sandstone-mudrock contacts. The source of calcium carbonate for calcite cement mainly came from around mudstone. High calcite cement content commonly results in low porosity and permeability. Individual glutenite thickness is also an important influencing factor on reservoir quality. Reservoirs with large thickness (&gt;4 m) have high porosity and permeability. Dissolution occurred in the reservoir, forming secondary dissolution pores and improving reservoir quality. The dissolution fluid for formation of secondary pores is mainly meteoric waters instead of organic acid. The reservoir property has an important influence on hydrocarbon accumulation. The lower limit of physical properties of an effective reservoir is a porosity of 27% and permeability of 225 mD. The findings of this study can be utilized to predict the reservoir quality of alluvial glutenite reservoirs effectively in the Bohai Bay Basin and other similar basins.

Architecture and exploration target areas of the Senegal Basin, West Africa

The recent discovery of large oil and gas fields in the deep-water of the Senegal Basin has drawn global attention. Despite this, several exploration wells in this area fail, which can be primarily contributed to a lack of understanding of the basin's structures and hydrocarbon accumulation conditions. This study examines these characteristics utilizing gravity, seismic and drilling data, and finally makes a comparison with the Cote d’Ivoire Basin, a typical transform margin basin in the South Atlantic. The results suggest that the Senegal Basin, influenced by multiple transform faults and a weak Paleozoic basement, experienced three evolutionary stages: rifting, transitional, and drifting. Each stage contributed to the development of distinct depositional sequences - syn-rift sequences, sag sequences, and continental margin sequences, respectively. The Triassic - Early Jurassic rifting stage predominantly formed continental deposits, like fluvial, lacustrine, and deltaic deposits, in the syn-rift sequences. The Middle-Late Jurassic transitional stage, influenced by transform faults, witnessed the formation of marginal ridges or submarine uplift zones. These zones, in conjunction with landward high terrains, formed a restricted environment promoting the development of source rocks in the sag sequences. During the drifting stage, three types of reservoirs, namely platform carbonate rocks, deltas, and slope-floor fans were formed. Notably, large-scale hydrocarbon reservoirs have been found in the deltas and the slope-floor fans both in the Senegal Basin and the Cote d’Ivoire Basin. The Upper Jurassic - Aptian platforms exhibit thick carbonate rocks and organic reefs on their edges, suggesting substantial potential for hydrocarbon exploration in the Senegal Basin.

Source and geological significance of Jurassic asphalt in the Ruoqiang Sag of Southeast Depression, Tarim Basin, Northwestern China

The Southeast Depression of the Tarim Basin has a very low petroleum exploration degree, and currently, no industrial oil and gas have been discovered. Many hydrocarbon shows exist in the Ruoqiang Sag, where hydrocarbon sources and accumulation processes are unclear. Only two potential Jurassic hydrocarbon source rocks developed in the Ruoqiang Sag, the Yangye (J2y) lacustrine mudstone of the Middle Jurassic and the Kangsu (J1k) coal-bearing mudstone of the Lower Jurassic. In this study, the Jurassic asphalt found in the QD1 well, combined with the source rocks of drilling cores and outcrops, was used to explore the possible hydrocarbon source and forming process in the Ruoqiang Sag using oil-source correlation and hydrocarbon accumulation geochronology methods. The asphalts have lower light and heavy rare earth fractionation than the J2y mudstone, and the total rare earth element (ΣREE) content, chondrite-normalized curves, and δEu and Y/Ho values are similar to those of the J1k mudstone, especially for the J1k coal. The n-alkane ratios of the carbon preference index and the odd-to-even preference (OEP) of Jurassic asphalts are greater than 1.0, indicating that its source rock has experienced low thermal evolution. All Jurassic samples have similar source-related biomarkers but different maturity-related parameters, and the thermal evolution degree of asphalt is close to the J1k mudstone and coal but slightly higher than the J2y mudstone. Meanwhile, rhenium–osmium isotopes show the asphalts are formed in 192+30/−45 Ma, which is similar to the J1k sedimentation time. The asphalts contain coal macerals and probably derived from the asphaltene precipitated by the J1k coal during the early coalification. The low abundance of 25-norbornanes with a non- or slight petroleum biodegradation degree indicates the asphalt was generated relatively late and migrated into the J2y formation along the faults, possibly accompanied by the striking activities of the Altyn Tagh Fault during the Neotectonics movement. This study provides evidence for the J1k coal-bearing strata serving as the effective source rock in the Ruoqiang Sag and increases confidence for Jurassic petroleum exploration in the Southeast Depression of the Tarim Basin. The structural and lithological traps near hydrocarbon source stoves, where Jurassic strata were deeply buried and far from the Altyn Tagh Range, are favorable oil and gas exploration targets.

Geochemical characteristics of Ordovician crude oils in the FI17 strike-slip fault zone of the Fuman oilfield, Tarim basin: Implications for ultra-deep hydrocarbon accumulation in the Tarim basin

The Ordovician crude oils in the Fuman Oilfield usually show varying physical properties and phase states along a single strike-slip fault. This study collected nineteen crude oil and gas condensate samples from the fault zones (FI17, FI19, and FI20) located in the eastern zone of the Fuman oilfield. Organic geochemistry methods were used to investigate the oil-source correlation, thermal maturity and secondary alternation processes of the samples, to reveal petroleum charge and accumulation models in ultra-deep reservoirs in the Fuman oilfield. The results showed that biomarkers of most crude oils have been modified by thermal stress, and the primitive geochemical information were distorted. Similar light hydrocarbon chromatogram characteristics and parameter ratios indicated that crude oils in the study area were generated from the same source rock. The carbon isotope of the whole oils (−31 ‰ to −33 ‰) and n-alkanes (−31 ‰ to −37 ‰) was comparable to the kerogen of the Lower Cambrian Yurtus Formation source rock (−30 ‰ to −37 ‰) considering both the carbon isotope fractionation between oils and kerogen and the effect of thermal maturity. The calculated equivalent vitrinite reflectance (%VRE) of oil and gas condensate based on adamantane, aromatic hydrocarbon and light hydrocarbon parameters ranged from 0.77 % to 1.44 %, suggesting a mature to highly mature hydrocarbon-generating stage. The lower dibenzothiophene content, 2-methylhexane/3-methylhexane ratios and relatively stable K1 values from light hydrocarbons revealed that the oil and gas condensates fluids were not subject to significant modification by thermochemical sulfate reduction (TSR). The calculated n-alkanes loss based on the whole oil gas chromatography ranging from 8 % to 26 %, suggested that the oil and gas condensate in the study area underwent relatively weak gas washing. Additionally, the concentrations of 3-methyldiamantane (3-MD) and 4-methyldiamantane (4-MD) in the samples ranged from 40.42 μg/g to 121.43 μg/g, showing realtively low oil cracking degree (<40 %) except for the gas condensates from the FI20 fault zone, whose oil cracking degree can reach 61 %. The comprehensive analyses in this study indicate that the differences in oil and gas physical property and phase state in the FI17 fault zone were primarily controlled by the vertical connectivity of the fault and the differences of crude oil charging periods. The hydrocarbon generation occurred during the early Caledonian period, followed by migration and accumulation in the Hercynian period, and subsequent adjustment and transformation in the Himalayan period. This study could provide significant exploration guidance for further ultra-deep oil and gas exploration in the Fuman oilfield.

Outcrops as windows to petroleum systems: Insights from the southern Bida Basin, Nigeria

The study assessed petroleum systems in the southern Bida Basin, Nigeria, focusing on the Cretaceous sediments. Reservoirs comprise Lokoja and Patti Formation sandstones, while shales, claystone, and siltstone serve as source rocks and stratigraphic traps/seals. Detailed studies delineating the key elements of the petroleum systems in the basin have not been conducted due to a lack of subsurface data. The goal of the current study was to use field observations, Scanning Electron Microscopy (SEM), X-ray diffraction (XRD), and geochemical and geomechanical data to evaluate key components of petroleum systems in the southern Bida Basin. The results presented in this investigation are intended to attain specific objectives, especially those lacking in the basin's study sections. Petrophysical analysis revealed that the Lokoja Sandstone has porosity of 37%–39.5% and moderate permeability of 23.22–42.29 mD. The Patti Formation sandstone reservoirs exhibited high porosity (38%–42%) and moderate to good permeability (31.54–66.48 mD), suggesting good potential reservoirs. SEM results revealed intragranular pores and micro-fractures in the Patti Shale, whereas the sandstone reservoirs in the Lokoja and Patti formations displayed fractures, facilitating hydrocarbon migration. Quartz was the dominant mineral in the sandstone units of both formations. XRD analysis revealed that brittle and clay minerals influenced the microstructure of Patti Shale. Geochemical analysis indicated promising petroleum potential in the Patti Shale, with a total organic carbon (TOC) content of 1.87 wt%, free hydrocarbon from kerogen (S1) of 0.41 mg/g, hydrogen index (HI) of 0.75 mg HC/g TOC, and production index (PI) of 0.17. The Patti and Lokoja formations' shale, claystone, and siltstone exhibited sealing potential, with a plasticity index of 24–35 and coefficient permeability of 2.8 × 10−4- 3.6 × 10−4 cm/s. Field studies, XRD, geochemical data, and geomechanical index values have confirmed the key components of the petroleum system, which in turn facilitate hydrocarbon generation, migration, accumulation, and entrapment in the basin.

Prediction of hydrocarbon accumulations using 2D basin and petroleum system modeling: Case studies from Abu Zenima and October fields in the Gulf of Suez, Egypt

This work aims to elucidate the potential applications of 2D basin and petroleum system modeling (BPSM) software in the assessment of hydrocarbon accumulations. To demonstrate how much information can be inferred regarding the existence of hydrocarbons and their mechanisms of accumulation in the subsurface, 2D BPSM was applied to two seismic sections that were utilized as case studies. The faults and horizons were digitally represented throughout the modeling phase to create the 2D BPSM for both seismic sections. The 2D BPSM construction used the age and lithology of each layer of the model as inputs. The hybrid technique was used to simulate hydrocarbon migration paths. The simulation findings showed that when the depth decreases, the degree of maturity declines, as some parts are characterized by transformation ratios of up to 100%. For the Upper Cretaceous source rock in model ABZ88-18, the levels of vitrinite reflectance (Ro%) are in the maturity phase and provide oil with Ro% values ranging from 0.6% to 1.3%. Whereas, in model 370, the Ro% values range from 0.55% to 1.3%. Based on the results of the modeling, new prospective hydrocarbon accumulations were found. Model ABZ88-18's estimated total mass is 292.9 million bbl oil and 11.49 million m3 gas, compared to model 370's estimated total mass of 178.52 million bbl oil.

Greenery planning for urban air pollution control based on biomonitoring potential: Explicit emphasis on foliar accumulation of particulate matter (PM) and polycyclic aromatic hydrocarbons (PAHs)

In this study, efficiencies of eight indigenous plants of Baishnabghata Patuli Township (BPT), southeast Kolkata, India, were explored as green barrier species and potentials of plant leaves were exploited for biomonitoring of particulate matter (PM) and polycyclic aromatic hydrocarbons (PAHs). The present work focused on studying PM capturing abilities (539.32−2766.27 μg cm−2) of plants (T. divaricata, N. oleander and B. acuminata being the most efficient species in retaining PM) along with the estimation of foliar contents of PM adhered to leaf surfaces (total sPM (large + coarse): 526.59−2731.76 μg cm−2) and embedded within waxes (total wPM (large + coarse): 8.73−34.51 μg cm−2). SEM imaging used to analyse leaf surfaces affirmed the presence of innate corrugated microstructures as main drivers for particle capture. Accumulation capacities of PAHs of vehicular origin (total index, TI > 4) were compared among the species based on measured concentrations (159.92−393.01 μg g−1) which indicated T. divaricata, P. alba and N. cadamba as highest PAHs accumulators. Specific leaf area (SLA) of plants (71.01−376.79 cm2 g−1), a measure of canopy−atmosphere interface, had great relevance in PAHs diffusion. Relative contribution (>90%) of 4–6 ring PAHs to total carcinogenic equivalent and potential as well as 5−6 ring PAHs to total mutagenic equivalent and potential had also been viewed with respect to benzo[a]pyrene. In−depth analysis of foliar traits and adoption of plant−based ranking strategies (air pollution tolerance index (APTI) and anticipated performance index (API)) provided a rationale for green belting. Each of the naturally selected plant species showed evidences of adaptations during abiotic stress to maximize survival and filtering effects for reductive elimination of ambient PM and PAHs, allowing holistic management of green spaces.

Carbon-based adsorbents for the mitigation of polycyclic aromatic hydrocarbon: a review of recent research.

Accumulation of polycyclic aromatic hydrocarbons (PAH) poses significant dangers to the environment and human health. The advancement of technology for cleaning up PAH-contaminated environments is receiving more attention. Adsorption is the preferred and most favorable approach for cleaning up sediments polluted with PAH. Due to their affordability and environmental friendliness, carbonaceous adsorbents (CAs) have been regarded as promising for adsorbing PAH. However, adsorbent qualities, environmental features, and factors may all significantly impact how well CAs remove PAH. According to growing data, CAs, most of which come from laboratory tests, may be utilized to decontaminate PAH in aquatic setups. However, their full potential has not yet been established, especially concerning field applications. This review aims to concisely summarize recent developments in CA, PAH stabilization processes, and essential field application-controlling variables. This review analysis emphasizes activated carbon, biochar, Graphene, carbon nanotubes, and carbon-nanomaterials composite since these CAs are most often utilized as adsorbents for PAH in aquatic systems.

Analysis of two-dimensional magnetotelluric inversion for the delineation of the petroleum system in the Kutai basin, East Kalimantan, Indonesia

The Kutai Basin in East Kalimantan is known as a potential area for oil and gas exploration. Two-dimensional magnetotelluric (MT) analysis is applied to investigate the geological structure and distribution of subsurface resistivity. This study aims to delineate the petroleum system using MT data and identify zones with potential for the accumulation of hydrocarbons. MT data has been collected at several strategic locations in the Kutai Basin, and two-dimensional cross-sections have been constructed to obtain vertical resistivity imaging at several depths. In this study, there were nine measurement points located on one line. The data is then inverted to obtain a two-dimensional resistivity model, which qualitatively represents the subsurface structure. The results of this study indicate that there is a low resistivity anomaly zone that identifies the presence of source rock with a resistivity value of 1-12 Ωm. In this line, it is suspected that the petroleum system that allows trapped hydrocarbons is found in the area, below the KT36 and KT13 measurement points. In this area there are folded structures in the form of synclines and anticlines, which raises suspicions about the types of traps formed from structural traps.

Role of keystone drives polycyclic aromatic hydrocarbons degradation and humification especially combined with aged contaminated soil in co-composting

Accumulation of persistent organic pollutants polycyclic aromatic hydrocarbons (PAHs) in soil has become a global problem. Composting is considered one of the more economical methods of soil remediation and is important for the resourceful use of wastes. Agroforestry waste is produced in huge amounts and is utilized at low rates, hence there is an urgent need to manage it. Here, leaf (LVS) or rice straw (SVS) was co-composting with aged contaminated soil to investigate bacteria interaction to PAHs degradation and humus formation. The degradation rate of high molecular weight PAHs (HMW-PAHs) in LVS and SVS reached 58.9% and 52.5%, and the low molecular weight PAHs (LMW-PAHs) were 77.5% and 65%. Meanwhile, the humus increased by 44.8% and 60.5% in LVS and SVS at the end of co-composting. The topological characteristics and community assembly of the bacterial community showed that LVS had higher complexity and more keystones than SVS, suggesting that LVS might more beneficial for the degradation of PAHs. The stability of the co-occurrence network and stochastic processes (dispersal limitation) dominated community assembly made SVS beneficial for humus formation. Mantel test and structural equation models indicated that the transformation of organic matter was important for PAHs degradation and humus formation. Degradation of HMW-PAHs led to bacterial succession, which affected the formation of precursors and ultimately increased the humus content. This study provided potential technology support for improving the quality of agroforestry organic waste composting and degrading PAHs in aged contaminated soil.

Research on fault-controlled hydrocarbon accumulation in rifted lacustrine basins based on structural geological modeling: a case study of the Banqiao area in Bohai Bay Basin, China

The Banqiao area in the Bohai Bay Basin has experienced three stages of extensional deformation, leading to the formation of numerous fault-bound traps. Faults, acting as boundary conditions for these traps, play a crucial role in hydrocarbon accumulation. In this study, we conducted a 3D structural modeling of the area using high-resolution 3D seismic data and established a fault-reservoir database based on previous research. Our findings reveal four levels of faults in the Banqiao area: basin-controlling faults, boundary faults, derivative master faults, and secondary adjusting faults. The structural units can be categorized into subsag areas, slope areas, stress tran-sition zones, bifurcation and main incised fault zones, and southern block areas. The segmented growth of the main boundary faults controls the evolution of the subsags, with the subsidence center gradually shifting eastward from Rift Phase I to Rift Phase II, aligning with the distribution of source rocks. Fault-bound traps in the Banqiao area include single faults, intersecting faults, and side faults. Faults primarily act as barriers to lateral hydrocarbon migration during the process of hydrocarbon accumulation, while also providing pathways to a lesser extent. By integrating the fault-reservoir database with the fault system classification, we identified four types of fault-controlled hydro-carbon accumulation models: like-dipping fault barrier model, oppositely-dipping fault barrier model, intersecting fault barrier model, and reactivation-controlled secondary hydrocarbon ac-cumulation model. This structural geological model effectively demonstrates the spatial configura-tion of faults and their role in hydrocarbon accumulation in the Banqiao area. The fault control mechanisms presented in the model can also be applied to other blocks in the Bohai Bay Basin, laying a foundation for future petroleum exploration in continental rifted basins and facilitating the ap-plication of big data algorithms in various geoscientific research fields.

Multi-stages of Paleozoic deformation of the fault system in the Tazhong Uplift, Tarim Basin, NW China: Implications for hydrocarbon accumulation

The Tazhong Uplift is an important petroliferous secondary structure unit in the Tarim Basin and has undergone multiple structural deformation. In the current study, we use 3D and 2D seismic data to investigate the nature of the fault system in the Tazhong Uplift. The deformation of the Cambrian sedimentary rocks in the Tazhong Uplift is generally neglected but noted in this study. We found that the Lower–Middle Cambrian rocks are involved in thrust faults. NE-trending weak zones acted as accommodation faults formed at the connective positions and bends of the deep thrust faults. The Middle Cambrian compressional stress stemmed from the northeastern margin of the Tarim Block, pointed SW, and caused the uprising of the Tabei Uplift. The second deformation occurred in the Late Ordovician. In this instance, the compressional stress stemmed from the SW direction of the Tazhong Uplift, which originated from the amalgamation of the Western Kunlun Terrane and Tarim Block. The main strike–slip fault surfaces and subordinate faults developed along the weak zones generated in the Middle Cambrian. The collision that occurred in the southeast part of the Tarim Block in the Middle Silurian to Middle Devonian resulted in the third deformation. The representative structures that occurred during this compressive deformation were the intensive NEE-trending thrust faults in the southeast of the Tazhong Uplift. The three stages of deformation played different and important roles in hydrocarbon accumulation. These strike–slip faults holding the high-productivity hydrocarbon wells generally experienced early-stage Cambrian deformation, had wide fracture damage zones in the Ordovician carbonate rock strata, and had weak en echelon faults in the Silurian to Middle Devonian clastic rocks.

The dominant mineralogical triggers hindering the efficient development of the world's largest conglomerate oilfield

In the complex fluid environment of subterranean rocks, some mineral components are easily hydrated, which hinders the accumulation and utilization of hydrocarbon. However, the nature and distribution of these key substances remain unclear. This study aims to provide a fresh perspective on the substances that impede the storage and extraction of hydrocarbon of the world's largest conglomerate oilfield. Using a variety of qualitative, semi-quantitative, and quantitative methods, including X-ray diffraction, secondary electron imaging, elemental spectroscopy, and Tescan-Integration-Mineral-Analyzer (TIMA), our experimental results show: (1) For the first time, water-sensitive clay minerals on the surfaces of gravel particles in tight conglomerates in China have been identified. Although the matrix composition contains less than 4.2% clay minerals on average, certain gravels contain over 72.7% clay minerals. These clay minerals are primarily composed of smectite, which is highly water sensitive, followed by chlorite, which poses significant challenges to hydrocarbon extraction; (2) The distribution of clay minerals on a single gravel surface is relatively uniform, enabling their interaction with fracturing fluid and exacerbating reservoir degradation. The total content of the illite-smectite mixture in the conglomerate can reach approximately 12%, with skeleton particles (gravel) containing more than 30% of this mixture. There are significant differences in the degree of clayiness among different types of gravel, which can be classified as high clayey, medium clayey, or low clayey. The evenly distributed illite-smectite mixed layer on the gravel surface allows complete contact with the fracturing fluid, resulting in severe reservoir damage; (3) Gravel particles with a size range of 8.88 μm–10.73 μm contain the highest concentration of illite-smectite mixture, which is identified as a major factor contributing to reservoir damage.

Assessment of Oil and Gas Potential in Vychegda Trough in Connection with the Identification of Potential Petroleum Systems

At present, the study of the oil and gas potential of poorly explored areas of oil and gas basins in the Russian Federation is of great importance due to the possibility of discovering large hydrocarbon accumulations in them. The Vychegda Trough in the north of the Volga–Ural basin is considered to be one of such areas. The research is devoted to the assessment of the oil and gas potential of the Vychegda Trough based on the concept of “petroleum systems”, which is widely used in oil and gas geology. A comprehensive analysis of geological and geophysical, petrophysical and geochemical data was carried out, and modern technologies for studying the oil and gas potential of sedimentary basins were applied: paleotectonic, paleogeographic reconstructions and basin modeling. The results of the research allowed us to determine a sufficiently high potential for the discovery of hydrocarbon accumulations and to identify three potential petroleum systems in the basin section: Riphean, Vendian and Devonian–Permian.

Fault Controls on Hydrocarbon Migration—An Example from the Southwestern Pearl River Mouth Basin

Faults play a pivotal role in controlling fluid migration and retention within sedimentary basins, particularly in the context of fault-bound hydrocarbon reservoirs. Assessing the stability and sealing capabilities of faults enhances our comprehension of these systems and aids in the identification of pathways for fluid migration. In this study, we focus on a series of fault-bound hydrocarbon accumulations located in the southern Wenchang A subbasin within the Pearl River Mouth Basin. We emphasize the significant influence of faults in governing the processes of hydrocarbon migration and accumulation. By leveraging 3D seismic data and well information, we have assessed the sealing potential of ten faults that either currently retain hydrocarbon columns or have the potential to do so. Our analysis reveals that even faults with a relatively low Shale Gouge Ratio (as low as 15%) can effectively support substantial column heights. Taking into account factors, such as the source rock maturity, fault activity, geometry, sealing potential, and the distribution of hydrocarbon accumulations, we have formulated a conceptual model for hydrocarbon migration and accumulation within the study area. This model underscores potential fluid traps within the rift basin, shedding light on the complex dynamics of hydrocarbon movement in this region.