Burial History Research Articles

Introducing Novel Correction Methods to Calculate Sedimentary Basin Overpressure and Its Application in Predicting Pressure Value and Origin

Overpressure is an important phenomenon observed in sedimentary basins. To enhance the precision of identifying the origin of overpressure and predicting it accurately, this paper presents four practical methods for analyzing formation overpressure, taking into account various factors, such as burial history, rock properties, mechanical models and data quality. By illustrating the application examples in typical basins, this paper demonstrates the practicality and potential of each model. Based on the analysis of organic matter content and denudation, our understanding of the origin of overpressure in the first member of the Cretaceous Qingshankou Formation in Songliao Basin has been revised. A novel model based on the static equilibrium equation was established, which not only demonstrates theoretical rationality but also exhibits practical advantages in the Junggar Basin and Southeast Hainan Basin. The incorporation of lateral loading in the correction model and the utilization of colored inversion in seismic velocity processing model have significantly enhanced pressure prediction accuracy in Junggar Basin and Southeast Hainan Basin, respectively. In conclusion, these correction models demonstrate a high level of reliability and possess significant potential for widespread adoption.

Temporal variations of mangrove-derived organic carbon storage in two tropical estuaries in Hainan, China since 1960 CE

Mangrove wetlands are important sites of carbon burial amounting to 15% of the global total for coastal environments even though they comprise only 0.5% of the coastal area. Carbon fixation and burial in mangrove wetlands are sensitive to environmental changes but difficult to quantify. In this paper, records of mangrove-derived organic carbon (OC) burial were analyzed for two mangrove wetlands, Bamen Bay estuary (BMB) and Danzhou Bay estuary (DZB), in Hainan Province, China, over timescales of the last few decades. The mangrove-specific biomarker taraxerol and the more established proxies of C/N ratio and δ13C of bulk OC were used to investigate OC sources and burial history. A mixing model based on C/N ratios, bulk OC δ13C values and taraxerol concentrations indicates that mangrove-derived OC accounts for 25 ± 14% (mean ± SD) of sedimentary OC burial in (BMB and 16 ± 7% in DZB since 1960 CE. The estimated top 100 cm organic carbon storage was 242 Mg/ha in BMB and 89 Mg/ha in DZB. The carbon sequestration rate in BMB increased from 0.29 Mg/ha/yr to 6.54 Mg/ha/yr after 2012 CE, likely as a response to local mangrove protection since 1981 CE. Compared to the less-protected DZB, mangroves in BMB contributed 31% more to the sedimentary OC pool after mangrove protection, suggesting that mangrove protection has the potential to increase ecosystem health and to increase carbon burial in coastal wetlands.

Response of Paleogene Fine-Grained Clastic Rock Deposits in the South Qiangtang Basin to Environments and Thermal Events on the Qinghai-Tibet Plateau.

The Chamdo Basin is a secondary basin in the eastern part of Tibet China and is one of the most promising of petroliferous basins for new petroleum exploration. The Qamdo Basin records a complex burial history from the Mesozoic to the Cenozoic; however, the poorly constrained sedimentology of Cenozoic strata in this basin has severely obscured the overall profile and impeded further explorations of oil and gas resources. Here, we conduct whole-rock geochemical analyses of major, trace, and rare earth elements in fine-grained clastic rocks of the Paleocene Gongjue Formation, Qamdo Basin to reveal depositional environments, provenance, and tectonic setting. Petrologically, the Gongjue Formation is dominated by red fine-grained sandy mudstones/siltstones with ripple marks. The high values of the chemical index of alteration (avg. of 78.93), chemical index of weathering (avg. of 90.10), and index of compositional variability (avg. of 2.5) suggest that the basin has undergone heavy weathering. Cross-plots of La vs Th, Th vs Sc vs Zr/10, and Th vs Co vs Zr/10 reveal a continental arc tectonic setting. Paleosalinity (Sr/Ba), paleoclimate (Sr/Cu), and redox proxies (V/Cr, U/Th, and enrichment factors of Mo and U) indicate brackish to saline and oxidizing paleowater masses during deposition of the Gongjue Formation. Provenance analyses via elements and petrology reveal that sediments in the Gongjue Formation are mainly derived from intermediate-acidic rocks of the upper crust. We conclude that the first and third members are more arid climate and heavily chemically weathered than the second member. In combination with previous studies of the structural evolution of the Qamdo Basin since the Paleogene, a model is built to describe the sedimentary environment and evolution of the Qamdo Basin during transition to the Paleocene. The first and third members, i.e., the Eg1 and Eg3 members of the Gongjue Formation, are dominated by an oxidizing environment of seawater-saltwater, and the climate ranges from warm and humid to arid and hot, with relatively stable environmental changes. The Eg2 member of the Gongjue Formation is dominated by an oxidizing environment of seawater-saltwater, and the climate ranges from warm and humid to arid and hot, with more frequent environmental evolution. Our model aids in better understanding of the Paleocene climate evolution of the eastern Tibetan Plateau.

Geochemical characteristics and hydrocarbon generation potential of main source rocks in the Upper Triassic Xujiahe Formation, Sichuan Basin, China

In order to have a comprehensive understanding of the characterization and hydrocarbon generation potential of the source rock in the Upper Triassic Xujiahe Formation, Sichuan Basin, the geochemical data of more than 1,500 cuttings and 106 core samples were collected and analyzed. The T3x5 member of Xujiahe formation show the highest average TOC content (3.63%) followed by the T3x1+2 and T3x3 members. The TOC contents of different members show a general decreasing trend from the bottom to the top in Xujiahe formation. From the rock pyrolysis and kerogen δ13C values, the source rock trend to be kerogen type III with minor amounts of type Ⅱ2. According to the Ro values, the Xujiahe source rock shows high maturity in the northwest and low maturity in the southeast. Most of the source rock in T3x1+2 members are in high to overmature stage, while most of the source rock in the T3x3 and T3x5 member are in the mature to high mature stage. By comparing the burial history and hydrocarbon generation evolution history of source rocks in central and western Sichuan basin, it can be found that the sedimentation rate differences during the Cretaceous period is the main cause of the thermal evolution difference of the source rock. The gas generation intensity and quantity of different members are also compared. The T3x5 member show the highest gas generation potential followed by the T3x31 and the T3x1+2 members. In general, horizontally, the source rock of Xujiahe formation in Sichuan Basin is characterized by great thickness, high maturity, and high gas generation intensity in the northwest, which are gradually decrease to the southeast. Vertically, the T3x5 member show the highest gas generation content, which account for 39.6% of the total amount.

Phanerozoic Tectonic and Sedimentation History of the Arctic: Constraints From Deep‐Time Low‐Temperature Thermochronology Data of Ellesmere Island and Northwest Greenland

AbstractRocks exposed along both sides of the Smith Sound in Ellesmere Island and NW Greenland record the tectono‐sedimentary evolution of the whole Phanerozoic, including two periods of mountain building—the Palaeozoic Ellesmerian Orogeny and the Palaeogene Eurekan Orogeny—and the formation of two major sedimentary basins, the Franklinian and the Sverdrup Basins. We used geo‐ and thermochronology and apatite chemistry data to unravel this evolution. Apatite fission track and (U‐Th)/He dates vary strongly from >600 to <100 Ma. We present internally consistent thermal history models, which allow to explain the data variations by a unitized exhumation and burial history. Our models suggest that the cratonic areas were buried beneath a several km‐thick succession of Franklinian Basin deposits. During the Ellesmerian Orogeny, the craton acted as sediment source, as also suggested by the composition of apatite and by U‐Pb ages of zircon contained in Devonian foreland sediments. The Ellesmerian foreland was buried by up to 4–5 km thick strata on top of the preserved sedimentary rocks. During the Triassic, the Sverdrup Basin strongly widened and extended at least ∼370 km further toward the east, as compared with previous reconstructions of the basin based on the preservation of Triassic deposits. Thermal history modeling suggests Late Cretaceous to early Cenozoic reheating, which may be caused by deposition associated with the Eurekan Orogeny and/or enhanced heat flow associated with continental breakup. Our data also show that low‐temperature thermochronology is not suitable for resolving potential strike‐slip movements along the Wegener Fault.

Genesis of Calcite Veins in 8# Coal Seam of the Upper Carboniferous Benxi Formation, Southeastern Margin of Ordos Basin

The 8# coal seam in the Benxi Formation of the southeastern margin of the Ordos Basin is a deep coal seam with abundant coalbed methane resources. Calcite veins are commonly developed within the 8# coal seam, and their formation processes and mechanisms have significant implications for the enrichment of deep coalbed methane. Genesis of the calcite veins was analyzed to reveal the impact of the calcite veins formation on coalbed methane accumulation, with an integrated application of petrographic study by thin section, cathodoluminescence analysis, carbon-oxygen isotope analysis, and homogeneous temperature measurements of fluid inclusions. The research findings indicate that the calcite veins in the 8# coal seam can be classified into three stages: C1, C2, and C3. The diagenetic fluids of C1 primarily originated from contemporaneous seawater. The fluids responsible for the formation of C2 primarily consist of organic fluids enriched in biogenic gas, whereas the fluids contributing to the formation of C3 are primarily associated with liquid hydrocarbons originated form decarboxylation of organic matter. Furthermore, the development of both C2 and C3 is influenced by deep hydrothermal fluids resulting from tectonic heating events during the Early Cretaceous. By combining analysis of the hydrocarbon accumulation history and burial history in the study area, it has been established that C2 formation occurred during the Late Triassic to Early Jurassic, while C3 formation took place during the Late Jurassic to Early Cretaceous. The exploration and production practices in the study area have firmly established the crucial significance of the formation and evolution of calcite veins within the 8# coal seam for the migration and accumulation of coalbed methane. The research outcomes provide valuable insights for the exploration of deep coalbed methane enrichment areas.

Control of faults and fractures on shale oil enrichment

The Qingshankou Formation is the primary shale oil exploration and development target in the Songliao Basin, but controlling factors of shale oil enrichment, especially the role of faults and fractures, are still poorly understood. We identify fault geometry in the Qingshankou Formation based on seismic interpretation. We characterize natural fractures with outcrop and core observations, and thin-sections petrography. By integrating faults and fracture observations at various scales, tectonic history of the basin, and burial history of the studied reservoir formation, we explain the control of faults and fractures on shale oil enrichment. Results show that high-density fault systems, namely “T11″ and “T2″ fault systems, were developed at the top and bottom of Qingshankou Formation in the north of Songliao Basin. Both fault systems is characterized as a group of high-density, closely spaced small faults forming a fault belt, with evident multi-stage activities. Nature fracture categories identified including folding and faulting related fractures, bed-parallel fractures and overpressure fractures, while the former two are better developed. Tectonic movements have caused the structural uplift and subsidence to take place at different times in different parts of the basin. The structural uplift happened late in the study area, consequently the source rocks have gone through a long burial history and are well matured, which favors shale oil enrichment. Tectonic uplifts generated large numbers of fractures locally, effectively increase oil production by improving the migration pathways and storage space of shale oil. Fault systems of different scale also provided two-way channels for oil migration in Qingshankou Formation. Large-scale faults that cut through the full shale column allow the shale oil to migrate to the conventional reservoirs above and below the Qingshankou Formation. The smaller faults in the high-density fault belt within the Qingshankou Formation (Qing-1 Member) enhanced seepage capacity and connectivity of the shale reservoir. As a result, shale oil and conventional oil development in the study area can collaborate with one another. High-density, well connected natural fractures also played an important role by providing storage space and fluid flow conduit which is essential in shale oil reservoirs. However, these fractures along faults may migrate oil from shale reservoirs to neighboring conventional reservoirs.

Linking diagenesis and reservoir quality to depositional facies in marginal to shallow marine sequence: An example from the Campano-Maastrichtian Gombe Sandstone, Northern Benue Trough, NE Nigeria

Fluvio-deltaic strata host significant volumes of hydrocarbons in different basins across the world, and are characterized by depositional heterogeneities and varying diagenetic overprints, owing to complex interactions of different depositional processes in diverse sub-environments. An understanding of the heterogeneities at different scales is critical to the prediction of reservoir quality distribution and architecture in these strata. The Campanian-Maastrichtian Gombe Sandstone is one of the targeted reservoirs in recent hydrocarbon exploration in the Northern Benue Trough, NE Nigeria. However, to date, the diagenetic and reservoir quality evolutions of the sandstone are not well understood. In this study, a multi-technique approach (consisting of thin-section petrography, scanning electron microscopy, and X-ray diffraction analyses) was employed to link depositional facies and diagenesis to reservoir quality. Results of the study indicate that the sandstones are principally arkosic and subarkosic in composition, and were deposited in lower delta front/prodelta, upper delta front/mouth bar, distributary channel, and interdistributary tidal bar/channel depositional environments. The sandstones experienced both shallow burial and some relatively of deep burial diagenesis. Kaolinite is the most abundant eogenetic cement in the sandstones, and was particularly found to be more abundant in the interdistributary tidal bar/channel and lower delta front/prodelta depositional environments due to their significant amounts of reactive detrital feldspars and muscovite precursors, respectively. The interdistributary tidal bar/channel and the distributary channel depositional facies were highly susceptible to siderite cementation, owing to their proximity to organic-rich mudstone lithofacies. Mechanical compaction was more intense in the lower delta front/prodelta than in the interdistributary tidal bar/channel sandstones, due to the presence of high clay matrix content in the former, which enhanced ductility and close packing. The interdistributary tidal bar/channel sandstones form the best reservoir quality because of the very low amounts of detrital pore-filling matrix (average 1%; n = 24) and less compaction compared to the lower delta front/prodelta, upper delta front/mouth bar and distributary channel sandstones. Grain-coating smectitic clays were best developed in the lower delta front/prodelta, upper delta front/mouth bar and distributary channel, whereas they are poorly developed in the interdistributary tidal bar/channel sandstones. The overall low volumes of deep burial, mesogenetic cements in the sandstones (e.g., illite, dickite, and quartz overgrowths) suggest that the Gombe Sandstone spent short residence time in mesogenetic realm before being uplifted. The results of this study would provide useful input data and understanding that can be utilized for forward diagenetic modelling and burial history construction for the subsurface Gombe Sandstone reservoir in the Northern Benue Trough and similar sedimentary formations elsewhere.

Impact of coal evolution on formation of tight sandstone reservoirs: A case study in the Daniudi gas field, Ordos Basin, China

Tight sandstone gas in coal-bearing strata has become an important unconventional gas worldwide. This research aims at understanding the impacts of coal evolution on diagenesis and reservoir quality of sandstones by means of thin section, cathode luminescence (CL), scanning electron microscope (SEM), stable isotope analysis, and fluid inclusions. The results show that carbonate cement was the main type of cement developed in tight sandstone reservoirs, of which the carbonate ions were jointly provided by coal layers and reaction in adjacent mudstones. For sandstones close to coal layers, their carbonate ions were mainly controlled by coal evolution and there was various carbonate cement developed due to cations supplied by seawater and the intense dissolution of volcanic fragments and feldspars. Combined with coal thermal simulation and burial history, it implies that at different maturity stages of coal evolution, its impact on sandstone diagenesis was different. In the early stage, the main product was CO2, which caused the dissolution of early calcite and promoted intense compaction. In the mature stage, CO2 and other hydrocarbon gases were released, resulting in more dissolution and silica cementation. In the over-mature stage, the main product was methane, and CO2 that did not spill out preserved by forming carbonate cement. The coal evolution had a strong impact on the reservoir quality of sandstone with large grain sizes, but little effect on medium- and fine-grained sandstones. High porosity and low permeability reservoirs were usually formed in small conglomerates and coarse-grained sandstones away from coal layers. While low porosity and high permeability reservoirs were distributed close to coal layers. This study aids in understanding the formation mechanism of tight sandstone reservoirs in coal measures and provides theoretic support for further exploration.

Lithology, facies and dynamics of formation of the albian-cenomanian reservoir rocks of the Pokuttya-Bukovyna part of the Carpathian autochthon

The purpose of this work is to study the Upper Albian-Lower Cenomanian psammitic complex of the platform basement of the Pokuttya-Bukovyna part of the Carpathian Foredeep, which is one of the main reservoir strata of the Lopushna oil field. Methodology. The complex of investigations includes correlation of the well-log data, lithological studies of core material, mineralogical and petrographic analysis of rocks, and paleogeographic studies of the sedimentary basin. Results. On the basis of the analysis of all existing wells, it was established that the deposits of the Late Albian-Early Cenomanian age within the entire territory of the autochthon of the Pokuttya-Bukovyna Carpathians are mostly represented by sandstones. They are composed of quartz (50-80%), feldspar (1–5%), muscovite (0.1-3%), pyrite (0.1-3%) and accessory minerals – zircon and epidote. A significant part of sandstone is composed of the authigenic minerals – glauconite (10-15%, sometimes up to 45%) and phosphate (1–3 up to 10%). The matrix in the rocks is mainly porous and contact-porous (10-15% of the rock volume), which provides these psammites with good reservoir properties. On the basis of paleogeographic reconstructions, it was established that in the Late Albian-Early Cenomanian, terrigenous sedimentation prevailed within the entire shelf basin of the Carpathian branch of the Meso-Tethys, which caused the accumulation of the thick sandstones’ strata. The burial history and post-sedimentary evolution of rocks took place under the influence of the thrusting of the Carpathian Fold Belt. This resulted in the formation of reservoir rocks and traps in the Upper Albian-Lower Cenomanian sequence. The peculiarities of hydrocarbon migration in the studied region indicate a high probability of discovering new deposits in the autochthon of the Pokuttya-Bukovyna Carpathians. Originality. The applied complex of lithological, geological-geophysical and paleogeographical studies made it possible to investigate the features of distribution of the Albian-Cenomanian psammite complex of rocks, both laterally and in section, their mineralogical and petrographic characteristics, sedimentary environments. The post-sedimentary evolution of the study strata and features of hydrocarbon migration were caused by the dynamics of the Carpathian Flysch Belt thrusting over the margin of the East-European platform. Practical significance. The obtained results show that the Upper Albian-Lower Cenomanian sandstones, which are oil and gas-bearing in the Lopushna field, represent the potential reservoirs in terms of both thickness and mineral composition within the entire autochthon of the Pokuttya-Bukovyna Carpathians. Since the Pokuttya fault could serve as a migration path for the hydrocarbons from the Carpathian flysch sequence into the platform basement strata, there is a high probability of the discovery of new accumulations in the structures similar to the Lopushna, revealed by seismic studies in the autochthon of the Pokuttya-Bukovyna Carpathians.

Petroleum geology and sub-source hydrocarbon accumulation of Permian reservoirs in Jinan Sag, eastern Junggar Basin, NW China

According to the latest drilling and the analysis of the burial history, source rock evolution history and hydrocarbon accumulation history, the sub-source hydrocarbon accumulation characteristics of the Permian reservoirs in the Jinan Sag, eastern Junggar Basin, are clarified, and the hydrocarbon accumulation model of these reservoirs is established. The results are obtained in four aspects. First, the main body of the thick salified lake basin source rocks in the Lucaogou Formation has reached the mature stage with abundant resource base. Large-scale reservoirs are developed in the Jingjingzigou, Wutonggou and Lucaogou formations. Vertically, there are multiple sets of good regional seals, the source-reservoir-caprock assemblage is good, and there are three reservoir-forming assemblages: sub-source, intra-source and above-source. Second, dissolution, hydrocarbon charging and pore-preserving effect, and presence of chlorite film effectively increase the sub-source pore space. Oil charging is earlier than the time when the reservoir becomes densified, which improves the efficiency of hydrocarbon accumulation. Third, buoyancy and source-reservoir pressure difference together constitute the driving force of oil charging, and the micro-faults within the formation give the advantage of “source-reservoir lateral docking” under the source rock. Microfractures can be critical channels for efficient seepage and continuous charging of oil in different periods. Fourth, the Jingjingzigou Formation experienced three periods of oil accumulation in the Middle–Late Permian, Middle–Late Jurassic and Late Neogene, with the characteristics of long-distance migration and accumulation in early stage, mixed charging and accumulation in middle stage and short-distance migration and high-position accumulation in late stage. The discovery and theoretical understanding of the Permian reservoirs in the Jinan Sag reveal that the thrust belt has good conditions for forming large reservoirs, and it is promising for exploration. The study results are of guidance and reference significance for oil and gas exploration in the Jinan Sag and other geologically similar areas.

Fluid Charging and Paleo‐pressure Evolution in the Ledong Slope Zone of the Yinggehai Basin, South China Sea

AbstractLarge numbers of gas reservoirs have been discovered in overpressure basins. Fluid charging has a close relationship with paleo‐pressure evolution, affecting the migration of gas reservoirs. To study fluid charging and the related pressure system, we analyzed burial histories and fluid inclusion (PVTx) simulations and conducted basin modeling of the Ledong Slope Zone in the Yinggehai Basin as an example. On the basis of fluid‐inclusion assemblages (FIAs), homogenization temperature (Th), final melting temperature (Tm, ice) and Raman spectroscopy in fluid inclusions, there are three stages of fluid charging: during the first and second stage, methane‐dominated fluid was charged at 2.2–1.7 Ma and 1.7–0.9 Ma, respectively. In the third stage, CO2‐rich hydrothermal fluid was charged since 0.9 Ma. It could be concluded from the well‐logging data that the disequilibrium compaction in the Yinggehai Fm., along with the fluid expansion and clay diagenesis in the Huangliu and Meishan formations, resulted in the overpressure in the Ledong slope zone. The evolution of paleo‐pressure was affected by the sedimentation rate of the Yinggehai Fm., as well as the hydrocarbon generation rate. Additionally, the Ledong Slope Zone is less affected by diapir activity than the nearby diapir area. Based on fluid inclusions, paleo‐pressure, basin modeling and geological background, the gas migration history of the Ledong Slope Zone can be divided into four stages: in the first stage, excess pressure was formed around 5 Ma; from 2.2 to 1.7 Ma, there was a reduction in the charging of hydrocarbon fluid and steadily increasing excess pressure; during the 1.7–0.9 Ma period a large amount of hydrocarbon was generated, excess pressure increasing significantly and hydraulic fractures forming in mudstones, With gas reservoirs developing in structural highs; since 0.9 Ma, CO2‐rich hydrothermal fluid accumulated in reservoirs adjacent to faults and the pressure coefficient remained stable. The research results are helpful in the study of fluid migration and accumulation mechanisms in overpressure basins.

The Rossano–San Nicola Fault Zone evolution impacts the burial and maturation histories of the Crotone Basin, Calabrian Arc, Italy

This work addresses the tectonic significance of a NW–SE-trending strike-slip fault zone in the Calabrian Arc of southern Italy, the Rossano–San Nicola Fault Zone (RSFZ). High-quality seismic reflection and 1D forward models of exploration boreholes and pseudo-wells show that the RSFZ experienced multiple Miocene phases of contractional/transpressional tectonics. These were followed by crustal extension during the Pliocene, which occurred in association with the oceanization of the Tyrrhenian Sea, Apennine orogenesis, and collision between the Calabrian Arc and adjacent tectonic plates. Such a setting had a profound influence on the Crotone Basin and its economic potential: (1) tectonic reactivation allowed reservoir units of the Crotone Basin to be charged by gas derived from Triassic/Lower Jurassic source rocks; and (2) source rocks reached their maximum depth and remained in the gas generation window after the emplacement of a large mass-transport complex in the Pliocene. In the surrounding areas, tectonic activity near the RSFZ contributed to source-rock maturation by enhancing local sedimentation rates, particularly during Langhian (Middle Miocene) and Zanclean (early Pliocene) tectonics. This work is important as it demonstrates that the tectonostratigraphic evolution of the Crotone Basin was closely related to the structural evolution of the RSFZ. Crucially, the study area reveals the first example of a gas field fully sealed by a large mass-transport complex. As a corollary, we tie the Late Cenozoic geological history of the Crotone Basin to the geodynamic evolution of the central Mediterranean region, namely the Ionian and Tyrrhenian seas. We identify new prospects in the Crotone Basin, and provide a time frame for gas generation and accumulation in southern Italy.

New insights into the stratigraphic evolution of SW Britain: implications for Triassic salt and hydrocarbon prospectivity

The discovery of Wytch Farm field in the Wessex Basin, and Kinsale Head field in the North Celtic Sea Basin in the early 1970s, led to exploration interest offshore in the Western Approaches Trough. Despite this activity, little evidence for prospective hydrocarbon resources has been found. To better understand the failures and analyse remaining hydrocarbon potential in this region, we make use of a large collection of new seismic reflection and well data to map Carboniferous to Neogene stratigraphy. The improved seismic imaging has allowed a better interpretation of the hitherto poorly understood, salt-related structures in the South Melville and the Plymouth Bay basins. The implications of the new interpretations for Carnian (Late Triassic), and Carboniferous stratigraphic and geodynamic evolution are assessed and contextualised with regional salt deposition in the Wessex, Bristol, and South Celtic Sea basins. From a petroleum system perspective, the Lias and Carboniferous source rocks are evaluated and modelled to analyse the maturity and evolution of the petroleum systems. We conclude that the Lias is an ineffective petroleum system due to timing and source maturation risk. However, the Triassic salt and associated subcropping faults have produced several possible pre-salt hydrocarbon traps. The traps may be charged from sporadic Mid-Late Carboniferous coal-bearing post-orogenic basins, a petroleum system previously overlooked. Thematic collection: This article is part of the New learning from exploration and development in the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin Supplementary material: Appendix showing seismic, well data and petroleum systems boundary conditions. Burial history plots of the petroleum systems modelling scenarios used to generate source rock transformation ratio plots shown in Figures 9 & 10 are available at https://doi.org/10.6084/m9.figshare.c.6486999

Characterising the economic Proterozoic Glyde Package of the greater McArthur Basin, northern Australia

The greater McArthur Basin is an informal term for a Palaeo-to-Mesoproterozoic sedimentary system that consists of terranes from the McArthur Basin, Birrindudu Basin, and the Tomkinson Province. These spatially distant basins are interpreted to connect in the subsurface based on geophysical, lithological, and geochronological evidence. The coeval sedimentary units of the greater McArthur Basin were subdivided into non-genetic depositional ‘packages’ bookended by regional unconformities. In ascending order, these packages are the: Redbank, Goyder, Glyde, Favenc, and Wilton Packages. The ca. 1660–1610 Ma Glyde Package is the focus of this study and includes the economically important Barney Creek Formation, found in the McArthur Basin sensu stricto. The Barney Creek Formation hosts the world-class, sediment-hosted, Zn-Pb-Ag McArthur River deposit. Importantly, it is also a key petroleum source rock and unconventional hydrocarbon reservoir, containing Australia’s geologically oldest oil and gas discoveries and forming a part of the McArthur Petroleum Supersystem. Consequently, identifying chronostratigraphically similar units elsewhere in the greater McArthur Basin is important for explorers in finding analogous economic resources.In situ Rb–Sr geochronological results of the Barney Creek Formation shales sourced from borehole LV09001 yielded ages of 1634 ± 59 Ma and 1635 ± 67 Ma. Shale samples from Fraynes Formation in borehole Manbulloo S1 were dated at 1630 ± 57 Ma and 1636 ± 42 Ma using the same approach. These ages are in good agreement with U–Pb ages of tuffaceous layers from the same units, suggesting that they represent their early burial histories and not secondary, post-depositional events. These results indicate that the Fraynes Formation and the Barney Creek Formation are direct chronostratigraphic equivalents, with ages within analytical error of each other.In addition to the geochronological similarities, the δ13Ccarb,87Sr/86Sr, and δ88/86Sr isotopic constraints from both units also display parallel geochemical fingerprints up-section. These include a positive δ13Ccarb excursion of ∼2.0 ‰, a trend towards more crustal-dominated 87Sr/86Sr ratios, and a negative δ88/86Sr excursion of ∼-0.25 ‰. These findings further support the application of isotopic chemostratigraphy as a powerful tool to correlate distal carbonaceous rocks in the basin system. Importantly, these geochemical fingerprints also show that the McArthur Group and the Limbunya Group experienced similar changes in palaeoenvironments during the evolution of the basin system. However, trace element data collated in this study indicates that they may have recorded different, heterogeneous palaeoredox histories. Geochemical models based on redox-sensitive trace elements V and Mo suggest that the Fraynes Formation sustained a much more euxinic water column as opposed to the Barney Creek Formation. These differences may have implications for the accumulation and preservation of base metals and hydrocarbons within the sediment.

Petroleum system modeling in complex tectonic setting; a study case of the Huallaga-Marañon retroforeland basin system, Peru

The present study explores the oil and gas potential of the Huallaga–Marañon Andean retroforeland basins in Perú, considering a regional transect which extends from the Eastern Cordillera in the west trough the Huallaga fold-and-thrust belt at the Andean deformation front to the Marañon Basin in the east. The sequential restoration of main tectonic events was derived from previous stratigraphic and structural interpretations revisited with reprocessed seismic lines, and new geochemical, petrographical, geochronological and thermochronological data. The resulting framework was tested in a 2-D Basin and Petroleum System Modeling (BPSM) to check the relationship between burial history, thermal maturity evolution and timing of hydrocarbon generation, expulsion and trapping at regional scale. BPSM suggests that during the Late Cretaceous (ca. 80 Ma) the petroleum generated in the Upper Triassic–Lower Jurassic source rock known as the Aramachay Formation migrated through the Middle–Upper Jurassic Sarayaquillo Formation basal sandstones up to 250 km and accumulated in the southeast of the Marañon Basin. From the Late Miocene, the reactivation of vertical faults favored the migration and accumulation of petroleum in Cretaceous siliciclastic reservoirs which is consistent with the hydrocarbon fields existence in this sector of the basin.In addition, results of modeling show that in the southwest of the Marañon Basin the development of structures during Late Miocene times postdated the generation and expulsion of hydrocarbons calculated for the Aramachay Formation which introduces a risk of synchronization between oil migration and charge. However, part of the generated hydrocarbons during the Late Cretaceous and Cenozoic are partially preserved in Jurassic reservoirs due to the high seal capacity of mudstones of the Sarayaquillo Formation. Such hydrocarbon fluids are redistributed and migrated into structural traps during Miocene times. In addition, the Miocene gas generation and expulsion also will reduce the risk of synchronization with the development of structures. In the Eastern Cordillera, organic-rich levels of the Aramachay Formation are in the late immature to early oil window show the occurrence of organic pores adding hydrocarbon storage capacity, suggesting this unit to be considered as a potential unconventional target in future exploration activities.

Characterizations of Middle–Lower Triassic Reservoir Quality and Gas Accumulations in the Northeastern Margin of the Ordos Basin, China

New Middle–Lower Triassic gas reservoirs were found in the eastern margin of the Ordos Basin, which provides new possibilities for gas exploration in the Ordos Basin. However, there are few relevant studies on these gas reservoirs. In this study, we use porosity–permeability measurements, optical light microscopy, scanning electron microscopy, mercury intrusion capillary pressure experiments, core-scale low-field nuclear magnetic resonance experiments, fluid inclusion analysis, burial history reconstruction, organic geochemistry data, and wireline log data to systematically investigate the reservoir quality and accumulation pattern of Middle–Lower Triassic gas reservoirs. The Middle–Lower Triassic sandstones are mostly lithic arkose, with a small amount of feldspathic litharenite. In comparison to the upper Paleozoic tight sandstone, the Middle–Lower Triassic sandstones exhibit a superior pore structure and increased porosity and permeability. A significant portion of the Middle–Lower Triassic sandstones can be referred to as “conventional sandstones” (porosities >12% and permeabilities >1 mD). The source rocks of the Middle–Lower Triassic gas reservoirs are most likely the upper Paleozoic coal and organic-rich mudstone, and the accumulation of natural gas occurred in the Early Jurassic to Late Cretaceous. The gas accumulation in the sandstones of the Middle–Lower Triassic reservoirs was mainly driven by buoyancy. The initiation and extension of vertical faults with small displacement in the northeast margin of the Ordos Basin enabled gas to move through the faults from the deep upper Paleozoic source rocks to the Middle–Lower Triassic reservoirs. Since gas accumulation relies on buoyancy, conventional sandstone layers with good reservoir properties are more likely to reach high gas saturation and are the primary targets for exploration and development.

Garnet growth and diffusion zoning during the late Paleoproterozoic metamorphism, North Altyn area, SE Tarim Craton, NW China: Implications for a long-lived hot orogen

Metamorphic rocks encode invaluable information on the burial and exhumation history of rocks that is critical to our understanding of orogens. In this work, zircon U−Pb dating, pseudosection, and garnet zoning modeling were performed on samples from the North Altyn area, SE Tarim Craton, NW China. Zircon U−Pb geochronological data indicate that the peak metamorphism occurred at ca. 2.0 Ga. Pseudosection isopleth thermobarometry using garnet growth zoning of the sample from the northern part of the North Altyn area (Kalatashtagh) reveals a decompression and heating path to a peak temperature of 735 °C and 0.74 GPa under the equilibrium crystallization model. The preservation of growth zoning under high temperature requires relatively rapid cooling. In contrast, garnet from the southern part of the North Altyn area (Aktashtagh) preserves diffusion zoning. Metamorphic peak occurs at 670−735 °C and 0.67−0.73 GPa, which suggests a high dT/dP-type metamorphism. Diffusion zoning modeling suggests an extremely slow cooling rate of 1−5 °C/m.y., which indicates prolonged (∼100 m.y.) crustal residence time at high temperature. This requires a long-term heat supply, most likely from radiogenic heat from buried sediments or heat conducted from the asthenosphere. The high dT/dP and slow cooling rate, combined with extensive crustal anatexis from previous studies, indicate that the late Paleoproterozoic North Altyn Orogen is a long-lived hot orogen rather than a subduction−accretionary complex. We propose a tectonic model that involves a ca. 2.1−2.0 Ga arc−back-arc system in the SE Tarim Craton. The back-arc basin was subsequently closed by northward underthrusting due to arc−arc/continental collision at ca. 2.0−1.95 Ga during the integration of the Tarim Craton into the Columbia/Nuna supercontinent.

Sequential restoration of Paradox Basin salt anticlines: Reconstruction of younger, eroded datums

Structural restoration is often accomplished by taking a folded, faulted stratigraphic horizon and transforming it back to its original, horizontal geometry. 2D sequential restoration uses a range of older to younger stratigraphic datums to reconstruct the geometric evolution of structural features through a history of multiple deformation events. For surface geology exposures, erosion may have eliminated some portions of younger horizons; these eroded gaps in stratigraphy can be mended using thickness trends to bridge the gaps. If a horizon has been fully exhumed, reconstruction of the missing stratigraphy can be inferred from burial history indicators in older, preserved units and from regional bridging from surrounding, less uplifted areas. In the Paradox Basin, late Cenozoic uplift of the Colorado Plateau has removed 1–2 km of Upper Cretaceous and Lower Tertiary stratigraphic units. Previous structural restorations have followed the structural evolution of the salt anticlines contained in the Paradox Basin from the late Paleozoic deposition of the salt-bearing Paradox Formation to end Jurassic deposition of the Morrison Formation. Yet, significant faulting and folding events continued through the Cretaceous and Tertiary. In order to capture the development of these structural features, this study reconstructs an inferred picture of the missing Upper Cretaceous and Lower Tertiary stratigraphy for Paleocene and mid-Eocene datums. Three Paradox Basin sections give an interpreted structural deformation of the salt anticlines for the Laramide event that affected much of the nearby Colorado Plateau and central Rocky Mountains. Restoration of unfaulted fold shapes show an early and very modest contractional shortening; interpreted Laramide fold amplification of the salt anticlines (∼100–150 m shortening per anticline) is followed by a later and more significant normal faulted extension (∼500 m extension per anticline). Both contraction and extension are detached from subjacent basement (= sub-Paradox) involvement. Location of basement shortening/stretching is beyond the extent of the interpreted sections and may lie within the structural features at the margins of the Paradox Basin.

A tropical soil (Lixisol) identified in the northernmost part of the Mediterranean (Istria, Croatia)

Terra rossa soils on the Istrian peninsula are generally considered polygenetic relict soils. They overlie and mark the youngest subaerial unconformity in the northwestern part of the Adriatic Carbonate Platform and are susceptible to erosional and redepositional processes. Terra rossa soils represent a valuable archive of information that can be used to understand present and past soil formation processes in the context of climate variability and landscape dynamics, especially in low-lying parts of the karst landscape where thicker deposits are typically found. We studied a 3 m thick terra rossa profile in a karst depression on the northernmost part of the southwestern Istrian planation surface and analysed the micromorphology, physical/chemical properties, geochemistry, bulk and clay mineralogy, and composition of heavy and light mineral fractions. The profile shows several signs of colluviation and polygenesis with clay distribution along the profile, clearly indicating lithic discontinuities. Kaolinisation, along with iron oxide formation, is the dominant process in the studied profile. Ferralitisation and lessivage processes were diagnosed throughout the profile, with intense clay translocation occurring despite the extremely stable soil microaggregates. In accordance with the WRB system, the profile is classified as Rhodic Lixisol (Clayic, Aric, Cutanic). This implies that some terra rossa soils, previously classified as e.g. Cambisols or Luvisols, might actually be Lixisols or other (sub-)tropical soils (e.g. Nitisols), in which relict properties are preserved in the present climate. The finding of a Lixisol in the study area indicates the old age of the surface of the karst depression and provides the first data on the burial history of the southwestern Istrian planation surface. We suggest the older Quaternary interglacials, the mid-Piacenzian Warm Period (Pliocene) and the Miocene Climatic Optimum as favourable periods for the formation of the studied soil.