Hydrocarbon Accumulation Research Articles

The Origin of Overpressure in the Pinghu Tectonic Zone of Xihu Depression and Its Relationship with Hydrocarbon Accumulation

Clarification of the cause of overpressure is of great significance for the study of hydrocarbon generation, migration and accumulation processes under an overpressure environment, and the prediction of predrilling pressure. The cause of overpressure in Xihu Depression is still controversial. This study, based on mudstone compaction research and organic matter correction of logging data, ascertained the causes of overpressure in the Pinghu tectonic zone, Xihu Depression. A modified discrimination method for overpressure genesis was used and the overpressure–hydrocarbon distribution relationship was explored. The results show the following: (1) Vertically, overpressure is located in the lower section of the Pinghu Formation, with a pressure coefficient of 1.1–1.7 and a pressure relief feature. On the plane, the pressure coefficient in the Pingzhong area exceeds that in the Pingbei area. (2) The main causes of abnormal high pressure in the research area are undercompaction and fluid expansion. The fluid expansion mechanisms include overpressure transmission and hydrocarbon charging within the reservoir as well as hydrocarbon generation pressurisation and overpressure transmission within the source rock. (3) In the surge section of kaolinite, under fluid pressure, kaolin migrates toward the low-pressure areas, decreasing the porosity in low-pressure areas and preserving pores in high-pressure areas. The evolution of fluid pressure can be divided into two stages: pressurisation; and both pressurisation and pressure relief. Pressurisation and pressure relief drive hydrocarbon charging, but hydrocarbons are more enriched in overpressure layers.

Characteristics and genesis of tuffaceous shale oil lithofacies:A case study of Lucaogou Formation in Santanghu Basin

Lucaogou Formation in the Santanghu Basin is a special lacustrine fine-grained sedimentary deposits rich in volcanic debris and carbonate, with abundant shale oil resources. However, understanding of shale oil characteristics and genesis remains unclear. Lithofacies, sedimentary environment, and formation mechanisms of tuffaceous shale oil are investigated based on core and thin section observations, X-ray diffraction, field emission SEM and geochemical analysis. Results show that three mixed lithofacies types are developed in Lucaogou Formation: blocky tuff, laminated tuffaceous dolomite, and laminated dolomitic tuff. These lithofacies types are characterized by high content of felsic and dolostone, widespread organic matter, and low clay content. Formation of tuffaceous shale oil sweet spots is primarily influenced by four factors: inputting of volcanic ash as a high-quality source rocks and reservoirs provides good material basis; devitrification of volcanic glass, calcitization, and dissolution are crucial for formation of reservoirs; expulsion of source rocks with high-abundance organic matter expulsion facilitates migration and accumulation of hydrocarbon in adjacent reservoirs; fracture development improves reservoir permeability to form highly productive sweet spots. By analyzing characteristics and genesis of tuffaceous shale oil, the main controlling factors of reservoir physical property and oil saturation are clarified, which is of great significance for selection of shale oil exploration zones.

Integrated 3D geological analysis of hydrocarbon maturation and migration in rift basins: Insights from the Niger Chad Basin

This study presents a comprehensive analysis of hydrocarbon maturation and migration in rift basins, with a particular focus on the Niger Chad Basin. The research employs advanced geological techniques, including 3D modelling, to provide essential insights. The use of 3D modelling techniques enhances the reliability of source rock data by accurately predicting vitrinite reflectance (Ro) and temperature values. This validation highlights the crucial importance of robust source rock characterization in hydrocarbon exploration. The role of fault systems in hydrocarbon drainage and accumulation is a prominent finding, with large-scale intra-basinal faults directing basin dynamics effectively. The timing of hydrocarbon generation relative to seal formation emerges as a pivotal factor affecting oil trapping, emphasizing the temporal aspects of petroleum system elements. The Madama Sandstone Formation plays a dual role as a reservoir rock and conduit for oil transmission, underscoring its significance in the hydrocarbon system. Its extensive lateral spread facilitates hydrocarbon drainage, revealing valuable insights into rift basin dynamics. In the future, further research should delve into the intricate interactions within rift basin systems, focusing on fault systems, source rocks, and reservoir rocks. Investigating the influence of lateral lithostratigraphic heterogeneity on hydrocarbon migration pathways is essential. Moreover, applying 3D modelling techniques to diverse rift basins worldwide will broaden our understanding of hydrocarbon maturation and migration, facilitating more precise resource assessments and exploration strategies. This research advances informed decision-making in hydrocarbon exploration and production.

Transport proteins and their differential roles in the accumulation of phenanthrene in wheat

The study focuses on the uptake, accumulation, and translocation of polycyclic aromatic hydrocarbons (PAHs) in cereals, specifically exploring the role of peroxidase (UniProt accession: A0A3B5XXD0, abbreviation: PX1) and unidentified protein (UniProt accession: A0A3B6LUC6, abbreviation: UP1) in phenanthrene solubilization within wheat xylem sap. This research aims to clarify the interactions between these proteins and phenanthrene. Employing both in vitro and in vivo analyses, we evaluated the solubilization capabilities of recombinant transport proteins for phenanthrene and examined the relationship between protein expression and phenanthrene concentration. UP1 displayed greater transport efficiency, while PX1 excelled at lower concentrations. Elevated PX1 levels contributed to phenanthrene degradation, marginally diminishing its transport. Spectral analyses and molecular dynamics simulations validated the formation of stable protein-phenanthrene complexes. The study offers crucial insights into PAH-related health risks in crops by elucidating the mechanisms of PAH accumulation facilitated by transport proteins.

Fracture distribution along open folds in southern Tunisia: implications for naturally fractured reservoirs

Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences of these networks. Our study focuses on the Southern Chotts–Jeffara Basin, which hosts reservoirs within Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proved that a regional shortening phase occurred between the Permian and Jurassic, forming open folds and a distributed fracture network. Analysis of late Paleozoic and Mesozoic outcrops within the basin has identified several sets of fractures (with dip directions and dip angles of 150/80 and 212/86) and compressional structural features that support this shortening hypothesis. We have integrated fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we found that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid-flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provide an insight into network characterization within naturally fractured reservoirs of Tunisia, and how certain structures form fluid pathways that influence flow and production. Supplementary material: Data and figures detailing fracture characterisation and modelling along open folds in southern Tunisia are available at https://doi.org/10.6084/m9.figshare.c.6904499

Structural differences and exploration potential of basins in the eastern and western branches of the East African Rift System

The East African Rift System (EARS) is the youngest rift with the eastern and western branches, consisting of multiple secondary rifts. It is generally characterized by low extent of exploration and great exploration potential. Identifying the differences in hydrocarbon accumulation conditions in various rifts is very important in providing guidance for hydrocarbon exploration and selecting favorable exploration targets in this area. Based on the interpretation of first-hand seismic-geological data, and combining other materials such as commercial databases and open access literature, the structural characteristics of the main rifts in the eastern and western branches of the EARS are comparatively analyzed; based on the anatomy of the discovered hydrocarbon reservoirs, the rifts of the EARS are classified into four types depending on their structural styles, including double-fault type, simple single-fault type, single-fault transfer type, and single-fault terrace type, and the control of structural style over hydrocarbon accumulation in the EARS is discussed. In the Western Branch of the EARS, large rifts such as the Albertine Rift and the Tanganyika Rift are mainly of double-fault type and single-fault transfer type, and only some small rifts are of the simple single-fault type. The rifts in the Eastern Branch of the EARS are generally small; the rifts in the northern section of the Western Branch are mainly of the simple single-fault type, and those in the southern section are mainly of the single-fault terrace type. The hydrocarbon potential of double-fault rifts is the greatest, followed by that of simple single-fault rifts and single-fault transfer rifts, and the hydrocarbon potential of single-fault terrace rifts is relatively limited. The results obtained from a comparative analysis of the structures, sediment fills, and reservoir elements of various rifts show that the west side of the Albertine Rift, the southeast of the Tanganyika Rift, the Kerio Rift, and the land in the northwest of the Turkana Rift have great exploration potential.

Scientific foundations of forecasting and searching for large accumulations of hydrocarbons

The article discusses the features of the formation of large reserves of oil and gas fields, confined to megareservaries. Based on the statistical analysis of the actual data for the 26 largest reserves of the world and Russian oil and gas fields, an assessment of the dependence of the reserves on the main geological factors involved in the formation of the deposit, such as the area of the deposit and the filtration and reservoir properties of reservoirs, is given. The criteria for forecasting large accumulations of hydrocarbons at different stages of geological exploration are proposed.

Implications of multi-stage deformation on the differential preservation of Lower Paleozoic shale gas in tectonically complex regions: New structural and kinematic constraints from the Upper Yangtze Platform, South China

The strength of tectonic deformation in tectonically complex regions, particularly multi-stage superimposed tectonic regions, can have a significant impact on shale gas preservation conditions. However, differential tectonic deformation has still not been quantitatively constrained, and its impact on the preservation conditions of shale gas is thus poorly understood in the northern Guizhou Province, southwest China. This study investigates the differential preservation conditions of marine shale gas in four eroded synclines (including Shixi, Daozhen, Zhongguan, and Fuyan Synclines) of the northern Guizhou Province. Interpretation of structures in field outcrops, geometry and kinematic analysis, and typical gas reservoir anatomy are combined to quantitatively explore the effect of superimposed deformation on the preservation conditions of shale gas. According to a set of new structural and kinematic constraints, the Riedel shear model for strike-slip faults is firstly conducted in the eroded synclines in the northern Guizhou Province, which innovatively established a linkage between detailed structural analysis and evaluation of shale-gas preservation conditions. We demonstrate that superimposing of deformations plays a role in differential accumulation in eroded synclines. The results indicate that (1) fault strike in the Shixi Syncline is more concentrated than Zhongguan and Fuyan Synclines, whereas fault strikes in the Zhongguan and Fuyan Synclines are more scattered. There is only one direction of maximum principal stress (σ1) in the Shixi and Daozhen Synclines. There are two maximum principal stress directions (σ1) in the Zhongguan and Fuyan Synclines. The Zhongguan and the Fuyan Synclines have tensional environments, whereas the Shixi and the Daozhen Syncline have compressional settings; (2) the formation dip angle, distance to a class II fracture, average detachment layer thickness, intensity of superimposed modifications, and interlimb angle may be positively correlated with gas content; (3) the progressive transformation pattern is established. These findings lay the foundation for the future research on the differential preservation mechanism of eroded synclines and may be useful for enhancing research on worldwide strike-slip faults controlling hydrocarbon accumulation.

Структура и эволюция углеводородных систем окраинных морей Северного Ледовитого океана (Восточная Арктика)

The article presents the results of studying the structure and evolution of hydrocarbon systems in the marginal seas of the Eastern Arctic — the Chukchi, East Siberian and Laptev Seas. The authors assess the hydrocarbon potential of the studied water areas basing on the results of the basin analysis and numerical modeling. Three promising sedimentary complexes Aptian–Upper Cretaceous, Paleocene–Eocene, and Oligocene–Lower Miocene are predicted in the composition of the sedimentary cover. It is shown that the development of hydrocarbon systems is determined mainly by the rate of sinking of the basins and the thickness of the formed overburden complexes. The main centers of hydrocarbon generation of the Aptian–Upper Cretaceous perspective complex are located in the North Chukchi trough, while those of the Paleocene–Eocene and Oligocene–Lower Miocene complex are located in the Laptev Sea basin. The most likely areas of hydrocarbon accumulation in the reservoirs of the Aptian–Upper Cretaceous complex are the marginal parts of the North Chukchi and East Siberian basins, where deposits are expected at a depth of ~5 km. In the Laptev Sea basin, in addition to the marginal zones, there is a large accumulation area in its central part with deposits predicted at a depth of ≥5 km. In the Paleogene (Paleocene–Eocene) complex, hydrocarbon accumulations are predicted mainly in the central parts of the studied basins and, to a lesser extent, in the near-side parts. The occurrence depths of promising objects vary from 5–6 km in the central parts to 2–3 km in the near-side ones. In the Oligocene-Lower Miocene complex, hydrocarbon accumulations are expected mainly within the Laptev Sea basin at depths of 3–5 km. Significant hydrocarbon potential may be associated with Paleogene clinoform deposits.

Restoration of reservoir diagenesis and hydrocarbon accumulation process by calcite in-situ U-Pb dating and fluid inclusion analysis: A case study on Cretaceous Qingshuihe Formation in Gaoquan Structure, southern Junggar Basin, NW China

The complexity of diagenesis and hydrocarbon accumulation in the deep reservoirs in southern Junggar Basin restricts hydrocarbon exploration in the lower reservoir assemblage. The lithofacies and diagenesis of reservoirs in the Cretaceous Qingshuihe Formation in the Gaoquan structure of the Sikeshu Sag, southern Junggar Basin were analyzed. On this basis, the thermal history was calibrated using calcite in-situ U-Pb dating and fluid inclusion analysis to depict the hydrocarbon accumulation process in the Gaoquan structure. The results show that the Qingshuihe reservoir experienced two phases of calcite cementation and three phases of hydrocarbon charging. The calcite cements are dated to be (122.1±6.4) Ma, (14.4±1.0) Ma – (14.2±0.3) Ma. The hydrocarbon charging events occurred at around 14.2–30.0 Ma (low-mature oil), 14.2 Ma (mature oil), and 2 Ma (high-mature gas). The latter two phases of hydrocarbon charging contributed dominantly to the formation of reservoir. Due to the S-N compressive thrust activity during the late Himalayan period since 2 Ma, the traps in the Gaoquan structure were reshaped, especially the effective traps which developed in the main reservoir-forming period were decreased significantly in scale, resulting in weak hydrocarbon shows in the middle-lower part of the structure. This indicates that the effective traps in key reservoir-forming period controlled hydrocarbon enrichment and distribution in the lower reservoir assemblage. Calcite U-Pb dating combined with fluid inclusion analysis can help effectively describe the complex diagenesis and hydrocarbon accumulation process in the central-west part of the basin.

Research progress and key issues of ultra-deep oil and gas exploration in China

Based on the recent oil and gas discoveries and geological understandings on the ultra-deep strata of sedimentary basins, the formation and occurrence of hydrocarbons in the ultra-deep strata were investigated with respect to the processes of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation, and key issues in ultra-deep oil and gas exploration were discussed. The ultra-deep strata in China underwent two extensional-convergent cycles in the Meso-Neoproterozoic Era and the Early Paleozoic Era respectively, with the tectonic-sedimentary differentiation producing the spatially adjacent source-reservoir assemblages. There are diverse large-scale carbonate reservoirs such as mound-beach, dolomite, karst fracture-vug, fractured karst and faulted zone, as well as over-pressured clastic rock and fractured bedrock reservoirs. Hydrocarbons were accumulated in multiple stages, accompanied by adjusting and finalizing in the late stage. The distribution of hydrocarbons is controlled by high-energy beach zone, regional unconformity, paleo-high and large-scale fault zone. The ultra-deep strata endow oil and gas resources as 33% of the remaining total resources, suggesting an important successive domain for hydrocarbon development in China. The large-scale pool-forming geologic units and giant hydrocarbon enrichment zones in ultra-deep strata are key and promising prospects for delivering successive discoveries. The geological conditions and enrichment zone prediction of ultra-deep oil and gas are key issues of petroleum geology.

Petrophysical and Geomechanical Analysis to Delineating Reservoirs in the Miocene Niger Delta Region of Nigeria

The application of various petrophysical and elastic metrics has advanced reservoir characterization and provided critical geological formation information. Porosity declines with depth, according to sonic, neutron, and density logs. Lithology, pressure, and hydrocarbons all contribute to this. Formation resistivity and fluid saturation are used to identify hydrocarbon-bearing zones. Because oil and gas are non-conductive, hydrocarbon-containing rocks are more resistant than water. In lithological categorization, gamma logs and the Vp/Vs ratio have helped classify reservoirs as Agbada Formation sand-shale reservoirs. Reservoir elastic characteristics, specifically sandstones, have been studied at various depths. These discoveries have an impact on their brittleness, strength, and failure risk in a variety of scenarios. Hydrocarbon accumulation has been influenced by diagenetic compaction equilibrium in pressure-exposed shale source beds. The research advances our understanding of the geological formations of the Niger Delta and gives practical insights for exploration and production. Decisions on oil and gas are based on hydrocarbon reservoir assessments at various depths, including porosity, fluid saturation, and lithology. Well logs from Wells B001, B002, and B003 revealed the diverse properties of several Niger Delta reservoirs. These discoveries have benefited hydrocarbon exploration and production decision-making significantly.

In-situ hydrocarbon formation and accumulation mechanisms of micro- and nano-scale pore-fracture in Gulong shale, Songliao Basin, NE China

By conducting experimental analyses, including thermal pyrolysis, micro-/nano-CT, argon-ion polishing field emission scanning electron microscopy (FE-SEM), confocal laser scanning microscopy (CLSM), and two-dimensional nuclear magnetic resonance (2D NMR), the Gulong shale oil in the Songliao Basin was investigated with respect to formation model, pore structure and accumulation mechanism. First, in the Gulong shale, there are a large number of pico-algae, nano-algae and dinoflagellates, which were formed in brackish water environment and constituted the hydrogen-rich oil source materials of shale. Second, most of the oil-generating materials of the Qingshankou Formation shale exist in the form of organo-clay complex. During organic matter thermal evolution, clay minerals had double effects of suppression and catalytic hydrogenation, which expanded shale oil window and increased light hydrocarbon yield. Third, the formation of storage space in the Gulong Shale was related to dissolution and hydrocarbon generation. With the diagenesis, micro-/nano-pores increased, pore diameter decreased and more bedding fractures appeared, which jointly gave rise to the unique reservoir with dual media (i.e. nano-scale pores and micro-scale bedding fractures) in the Gulong shale. Fourth, the micro-/nano-scale oil storage unit in the Gulong shale exhibits independent oil/gas occurrence phase, and shows that all-size pores contain oils, which occur in condensate state in micropores or in oil-gas two phase (or liquid) state in macropores/mesopores. The understanding about Gulong shale oil formation and accumulation mechanism has theoretical and practical significance for advancing continental shale oil exploration in China.

Progress in and research direction of key technologies for normal-pressure shale gas exploration and development

Normal-pressure shale gas is an important object of shale gas reserves and production increase with broad resource prospects in China, but its large-scale benefit development is still confronted with technical bottlenecks. To promote the large-scale benefit development of normal-pressure shale gas, this paper systematically sorts out and summarizes the research achievements and technological progresses related to normal-pressure shale gas from the aspects of accumulation mechanism, enrichment theory, percolation mechanism, development technology, and low-cost engineering technology, and points out the difficulties and challenges to the benefit development of normal-pressure shale gas in the complex structure zones of southern China, by taking the shale gas in the Southeast Chongqing Area of the Sichuan Basin as the research object. In addition, the research direction of normal-pressure shale gas exploration and development is discussed in terms of sweet spot selection, development technology policy, low-cost drilling technology and high-efficiency fracturing technology. And the following research results are obtained. First, the accumulation mechanism of normal-pressure shale gas is clarified from the perspective of geological exploration theory; the hydrocarbon accumulation model of generation, expulsion, retention and accumulation is established; the enrichment theory of “three-factor controlling reservoir” is put forward; and the comprehensive sweetspot target evaluation system is formed. Second, as for development technology, the development technology policies of “multiple series of strata, variable well spacing, long horizontal section, small included angle, low elevation difference, strong stimulation and pressure difference controlling” are formulated. Third, as for drilling engineering, the optimal fast drilling and completion technology with “secondary structure + radical parameter + integrated guidance + unpressured leak-proof cementing” as the core is formed. Fourth, as for fracturing engineering, the low-cost and high-efficiency fracturing technology with “multi-cluster small-stage + limited-entry perforating + double temporary blocking + high-intensity sand injection + fully electric” as the core is formed. Fifth, normal-pressure shale gas is characterized by complex geological conditions, low pressure coefficient and gas content, poor resource endowment and so on, but its resource utilization still faces a series of challenges, such as uncertain productivity construction positions, low single-well productivity and ultimate recoverable reserve, high investment cost and poor economic benefit. In conclusion, the key research directions to realize the large-scale benefit development of low-grade normal-pressure shale gas are to deepen the research on the enrichment and high yield mechanism and sweet spot selection of normal-pressure shale gas, strengthen the research on the benefit development technology policy based on percolation mechanism and the key technologies for low-cost drilling, accelerate the research and development of the key technologies for low-cost and high-efficiency fracturing, and implement cost reduction and efficiency improvement continuously.

Origin of gas condensate reservoir in Fuman Oilfield, Tarim Basin, NW China

To understand the reservoir property and hydrocarbon accumulation conditions of the Middle and Upper Ordovician intraplatform shoal between ultra-deep main strike-slip faults in Fuman Oilfield of the Tarim Basin, China, the main strike-slip faults in and around well FD1 in the basin were analyzed in terms of sedimentary facies, sequence stratigraphy, intraplatform shoal reservoir property, and oil and gas origins, based on drilling data. The Yingshan Formation intraplatform shoal between the main strike-slip faults is superimposed with low-order faults to form a new type of hydrocarbon play. Firstly, hydrocarbons generated from the Lower Cambrian Yuertusi Formation source rocks vertically migrated into the second member of Yingshan Formation through the main strike-slip faults, and then migrated laterally until they were accumulated. A small amount of oil from Well FD1 came from the Yuertusi Formation source rocks in the mature stage, and a large amount of gas originated from oil cracking in the ultra-deep reservoirs. Therefore, the secondary gas condensate reservoir in Well FD1 is characterized by high gas to oil ratio, dry gas (dryness coefficient being 0.970) and hybrid origin. This new type of hydrocarbon play characterized by intraplatform shoal and low-order fault suggests a prospect of continuous hydrocarbon-bearing area in Fuman Oilfield, which will expand the ultrap-deep oil and gas exploration in the oilfield.

Integrated Study for Seservoir Characterization of Kadanwari Area of Lower Indus Basin, Pakistan Using Seismic Data and Well Data

As a developing nation, Pakistan is confronted with serious energy challenges as a result of a scarcity of hydrocarbons. And the major objective of this paper is to assess the hydrocarbon potential of a study zone in Pakistan’s central Sindh Basin, which is known as the Kadanwari Gas area. The characterization of the reservoir has been accomplished by the use of conventional geophysical techniques, including 2D seismic data and well log information. By converting the time structure map of seismic, it is possible to produce the depth contour map. And a method for converting seismic data to Acoustic Impedance is described. Based on well logs collected after drilling, Petro-physical characteristics such as shale volume, porosity, water saturation, and hydrocarbon saturation were calculated. It was established that the review area is part of the extensional structural system by normal faulting that was seen on seismic sections. The seismic interpretation of these lines that emerged proved the existence of the Horst and Grabben structures as a consequence of normal faulting. The region around these buildings has a significant amount of potential for hydrocarbon accumulation.

Structural and stratigraphic controls on reservoir architecture: A case study from the lower Oligocene Vicksburg Formation, Brooks County, Texas

A detailed structural and stratigraphic framework provides a precise understanding of the controls on the vertical and spatial distribution of reservoir units, as well as the identification of the most prospective hydrocarbon accumulation. In southern Brooks County, Texas, the Lower Oligocene Vicksburg Formation (LOVF), is being influenced by the Vicksburg Fault Zone (VFZ). This zone is characterized by listric-normal faults that have formed highly faulted rollover anticlines, which are valuable structural traps for hydrocarbon exploration. This study integrated 568 3D seismic lines, 39 well logs, and three velocity surveys to build a comprehensive conceptual model that explores how secondary synthetic (dipping east), antithetic (dipping west), and Texas Gulf Coast-perpendicular faults are influencing accumulation and spatial distribution of hydrocarbons within the LOVF (La Rucias Field). Results indicate that synthetic, antithetic, and coast-perpendicular faults affecting the V-102, V-17, and V-19 horizons provide conduits for hydrocarbon migration. Antithetic faults and coast-perpendicular faults within the rollover anticline are terminating beneath an overlying shale seal layer between the V-16 and V-17, influencing economic hydrocarbon accumulations through multiple reservoirs. While synthetic faults affect the overlying seal layer migrating hydrocarbon out of the V-102, V-17, and V-19, bidirectional faulting linking antithetic and coast-perpendicular faults provide additional pathways for hydrocarbon accumulation. Spatial distribution of hydrocarbons varies with the targeted horizon. V-102 reservoirs are situated on the western flank of the rollover anticline, whereas the V-17 and V-19 reservoirs are located on structural highs where overlying shale seal layer remains unaffected by the antithetic faults. V-17 and V-19 reservoirs are influenced by bidirectional faulting that terminates beneath the shale seal layer, enabling the accumulation within the rollover anticline. Petrophysical and lithological investigations of the seal layers within the V-102, V-17 and V-19 are highly recommended for better understanding of vertical compartmentalization of reservoir intervals and accumulation estimates within the La Rucias Field. Investigating the control of these fault systems enhances our understanding of subsurface fluid migration and accumulations (oil, gas, groundwater, and contaminants) in the expanded Vicksburg productivity trends. Furthermore, the insights gained from the examination of these fault systems not only contribute to our comprehension of subsurface fluid migrations within the Vicksburg trends but also serve as a valuable reference for similar geological systems and reservoirs worldwide, ultimately aiding in the development of more effective resource management.

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

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

Deciphering the origin and secondary alteration of deep natural gas in the Tarim basin through paired methane clumped isotopes

The Tarim Basin is one of the most complex, ancient, and petroliferous deep craton basins in the world. Multiple sets of source rocks, stages of tectonism, and episodes of hydrocarbon generation and accumulation complicate the formation and evolutionary processes of hydrocarbons in the basin, especially for the deeply buried petroleum system at >6000 m depth. Paired clumped isotopes (Δ13CH3D and Δ12CH2D2) allow the investigation of methane isotopic bond ordering, elucidating the methane generation mechanism and its post-generation processes, which can complement studies of the molecular and conventional stable isotopic compositions of gas hydrocarbons in constraining the origin and source of natural gas. This study focused on methane clumped isotopes, and chemical and conventional stable isotopic compositions of natural gas samples from four typical oil and gas regions of the Tarim Basin. Results indicate that these gases are thermogenic gases with relatively high stable isotopic δ values (i.e., −46.1‰ < δ13C–CH4 < −25.9‰, −184‰ < δD-CH4 < −140‰). Most exhibit equilibrium methane clumped isotope signatures at temperatures of 128–257 °C, consistent with the main oil-window to gas-window region. The clumped isotope apparent temperature of equilibrated methane was used to determine its formation temperature, which was applied for gas–source correlations and thermal maturity assessments of the natural gases based on the results of previous basin modeling. The clumped isotope compositions of two gas samples from the Keshen area of the basin are characterized by significant deficits in Δ12CH2D2 values but with similar Δ13CH3D values to those of other equilibrated gases there, indicating the possibility of methane bond re-ordering at high temperatures (>300 °C) exceeding the methane “closure temperature”. Non-equilibrium gases in the Tabei area yielded a plausible Δ13CH3D apparent temperature (<160 °C) with a pronounced deficit in Δ12CH2D2 values, possibly owing to irreversible chemical kinetic processes in thermal cracking of organic matter at early thermal maturity (Ro < 1.5‰) or mixing between thermogenic gases generated at two distinct temperatures (i.e., ∼200 °C and ∼120 °C). Equilibrium clumped isotope signatures also rule out the possible effects of secondary alteration on natural gases in the Hetianhe area that were previously considered in conventional isotope studies. Such findings demonstrate that methane clumped isotopes provide independent and effective indicators of gas–source correlations in deep basins while also elucidating secondary processes that are often under- or over-estimated in conventional stable isotope studies.

Sub-basalt hydrocarbon prospect assessment in Peninsular India using seaward dipping reflectors

Conventionally, volcanic margins have been considered devoid of hydrocarbon, but many discoveries and research in recent past have proved the presence of hydrocarbon prospects within them. However, hydrocarbon exploration within volcanic margin is constrained by seismic imaging. Further, identification of continent to oceanic boundary (COB) is critical to hydrocarbon search as hydrocarbon is found mostly over continental crust. Seaward dipping reflectors, associated with volcano-sedimentary sequences, located along rifted continental margins and represented by highly dipping strong amplitude seismic reflectors, play an important role to study volcanic margins. Keeping in view the problems of hydrocarbon exploration within volcanics, seaward dipping reflectors (SDRs) in Indian context have been studied in detail in this paper. It facilitates mapping of continent-oceanic boundary (COB). It has impact on hydrocarbon prospectivity in volcanic margins as it can provide formidable seal and secondary induced maturity. In India, several discoveries have been made in volcanic margins along west coast, from weathered, fractured basalt and sub-basalt sediments. In the present work, long offset regional seismic data (18 dip lines and 1 cross line), along east coast, have been interpreted. SDRs help in hydrocarbon prospectivity assessment for both discrimination of interbedded sediments and preferential accumulation of hydrocarbon. Mapping of linear features not only helped to demarcate COB but also their presence at 6–10 km depth. For the first time, such comprehensive study on SDRs has been done along Indian peninsular region with indications for hydrocarbon prospectivity at deeper levels along Indian peninsular region.