Petroleum System Research Articles

The significant meaning of biodegradation to the petroleum system of the Seram Basin, eastern Indonesia: evaluation on the basis of physio-chemical composition variation of Seram oils

It has been widely accepted since the 1980s that Seram crude oils belong to one family that originated from the Triassic carbonate source rock. Even though these oils share similar nature and origin, they exhibit wide physio-chemical composition variations in Seram Basin. Moreover, this variation is also noted within a similar oil field. Hydrocarbon alteration, especially biodegradation, a process of hydrocarbon destruction by microbial activities, has been attributed to this variation. However, the degree and extension of biodegradation in the Seram Basin are still poorly understood. Therefore, crude oils accumulated in main reservoirs, the Pre-Tertiary Manusela Carbonate and the Pliocene Fufa Clastic reservoirs, retrieved from Lofin, Oseil, Nief, and Bula Fields, are comprehensively studied. In addition, several oil seep samples were also utilized for this study together with crude oil geochemistry data compiled from previous publications. The occurrence of biodegradation is also validated with the geological conditions that include resevoir temperatures and salinities. Based on the geochemical signatures, there is a wide range of biodegradation degrees within the Seram Basin with the biodegradation degree tends to increase and more destructive to Bula Field which is situated in the northern part of the basin. The biodegradation pattern is linked to hydrocarbon generation and migration history. The Neogene deformation in eastern Indonesia is interpreted to be responsible for the different biodegradation process within Seram Basin. This process should be well understood and not be neglected during petroleum exploration, especially in eastern Indonesia. This study shows that such simple process has a deep meaning on the petroleum system history, especially the hydrocarbon preservation in the reservoir.

Structural inheritance in the Chukchi shelf, Alaska

Interpretation of over 100,000 line-km of reprocessed 2D, time-migrated, seismic-reflection data from the U.S. Chukchi shelf documents at least four tectonic events in the last 400 m.y. that generated distinct inherited structures. A well stratified economic basement whose internal geometry clearly defines a pre-Mississippian, thin-skinned fold-and-thrust belt represents the earliest recognizable tectonism in the area, one that accommodated west-east (present-day coordinates) shortening, probably in the Devonian. (1) The first inversion event, and dominant crustal feature in the Chukchi shelf, is the Hanna Trough, a north-south, failed rift system that accommodated more than 10 km of Carboniferous-Jurassic syn-rift and post-rift (sag) strata. Carboniferous extensional collapse of the previous orogenic belt to form the Hanna Trough was influenced heterogeneously by the pre-Mississippian contractional fabrics. Many rift-phase normal faults detach along pre-Mississippian thrust faults in discrete negative inversion, creating distinctive synthetic growth strata that constrain the geometry of extension. Other normal faults cut across pre-Mississippian stratigraphy showing more typical rollover geometries in growth strata and dissection of contractional structures in the pre-rift strata in more distributed negative inversion. (2) After a period of Pennsylvanian to Early Jurassic subsidence, in the south-central Chukchi shelf several north-south, rift-phase normal faults were inverted in a second event in the Late Jurassic to Early Cretaceous, forming local, asymmetric, positive inversion structures due to west-east shortening likely associated with far-field effects of the Chukotkan orogeny. The Hanna Trough then was buried beneath >2 km of Cretaceous and Cenozoic foreland-basin deposits during which complex additional deformation occurred in the region. (3) The North Chukchi high resulted from Late Cretaceous-Paleogene deep thrusting, both south- and north-directed, and possible transpressional inversion across a complex older structural fabric. (4) Cenozoic east-west extension and strike-slip faulting in the northern Hanna Trough reactivated Carboniferous rift structures, in the west as dominantly discrete motion on the older faults, and in the east in more distributed fashion coalescing near older rifts and cutting Late Cretaceous-Paleogene contractional structures during a final negative inversion. Documentation of multi-phase structural inheritance in the Chukchi shelf is vital to unraveling the tectonic history and influences on petroleum systems in the area.

An MPA-based optimized grey Bernoulli model for China’s petroleum consumption forecasting

The remarkable prediction of petroleum consumption is of significance for energy scheduling and economic development. Considering the uncertainty and volatility of petroleum system, this paperpresents a nonlinear grey Bernoulli model with combined fractional accumulated generation operator to forecast China’s petroleum consumption and terminal consumption. The newly designed model introduces a combined fractional accumulated generation operator by incorporating the traditional fractional accumulation and conformable fractional accumulation; compared to the old accumulation, the newly optimized accumulation can enhance flexible ability to excavate the development patterns of time-series. In addition, to further improve the prediction performance of the new model, marine predation algorithm is applied to determine the optimal emerging coefficients such as fractional accumulation order. Furthermore, the proposed model is verified by a numerical example of coal consumption; and this newly established model is applied to predict China’s petroleum consumption and terminal consumption. Our tests suggest that the designed ONGBM(1,1,k,c) model outperforms the other benchmark models. Finally, we predict China’s petroleum consumption in the following years with the aid of the optimized model. According to the forecasts of this paper, some suggestions are provided for policy-makers in the relevant sectors.

Unlocking the Hydrocarbon Potential of the Mannar Basin (Sri Lanka) Based on New Data and New Ideas

The Mannar Basin is a failed rift basin located between Sri Lanka and India. Massive flood basalts have been deposited during latest Cretaceous/earliest Paleocene magmatic activity that is also represented by numerous igneous sill intrusions. The two discoveries are associated with this magmatism: Barracuda and Dorado, both discovered in 2011, have been drilled in the northern part. One of the key challenges for hydrocarbon exploration in volcanic provinces is sub-basalt imaging due to the velocity contrast between basalts and siliciclastics. To unlock hidden play types and identify geological features within Mesozoic intervals we utilized both infill 2D seismic data acquired in 2018 and vintage 2D seismic data reprocessed in 2021. These provide new insights for hydrocarbon exploration and the tectono-stratigraphic evolution of Sri Lanka’s offshore basins. We integrated these new study results into a regional 2D petroleum system modelling study. Modelling results indicate hydrocarbon potential for several play types: Cretaceous reef, turbidite and fan plays. Since the tectonic evolution of the Mannar Basin is still a matter of debate, especially related to timing and duration of extension and Sri Lanka’s position during Gondwana breakup, we created different heat flow scenarios to validate the impact on the hydrocarbon prospectivity.

Effects of confining pressure and microscale heterogeneity on hydrocarbon retention and pore evolution from artificial maturation of Eagle Ford Shale

Although shale heterogeneity has recently emerged as a key topic in unconventional petroleum systems, hydrocarbon (HC) retention and pore evolution in organic-rich shales still remain poorly constrained. In this study, an organic-rich Eagle Ford Shale sample (EqVRo = 0.92%) from a shale-oil prospecting well in South Texas was selected for gold-tube pyrolysis experiments to investigate organic matter (OM) -hosted pore development versus confining pressure during thermal maturation. Before heating, the OM-type heterogeneity and associated pore characteristics in the sample were examined by thin section and scanning electron microscopy imaging, combined with elemental mapping by X-ray energy-dispersive spectroscopy. Four forms of OM occurrence that are closely associated with different mineral matrix domains are distinguished, including the ductile oil-bearing primary OM and rigid primary OM in the siliceous-argillaceous seams, as well as the secondary OM in coccolith-rich lenses and in foraminifera chambers. From heating experiments, the pressure effect on pore evolution was found to be pronounced for the secondary OM in the foraminifera chambers, in which the coalescence of small pores to larger pores upon OM maturation was accelerated by increasing fluid pressure, accompanied by arrangement and densification of OM structures. However, the expulsion effect as a function of confining pressure seems to be evident only for the secondary OM in the coccolith-rich lenses. In contrast, the two types of primary OM in the siliceous-argillaceous seams do not show any apparent changes in pore development over the investigated pressure range of 10 to 120 MPa, probably due to stiffer mechanical properties of primary OM as compared to secondary OM. The discrepancies in pore evolution of different OM types as a response to the variation in confining pressure upon maturation primarily depend on the physical-chemical properties of these various OM materials.Of further importance, observed differences in OM evolution and associated pore characteristics in response to the variation in confining pressure imply that the microscale heterogeneity of shale fabric controls the extent of oil retention and pore evolution. In contrast to the intragranular pores in the foraminifera chambers, the intergranular pores in the coccolith-rich lenses from the Eagle Ford Shale sample are relatively smaller, yet more likely interconnected. Thus, these coccolith-associated pores may provide not only significant storage space but also a major flow pathway for HC production. Our investigation at the microscopic scale provides concepts indicating that HC retention and OM-hosted pore evolution occur differently in two contrasting types of mineral matrix pores, which is critical to successful unconventional shale oil and gas exploration in sedimentary basins.

Evaluation of Neoproterozoic source rock potential in SE Pakistan and adjacent Bikaner–Nagaur Basin India

Discoveries of heavy crude oil in the Neoproterozoic rocks (Infracambrian rock sequence) from the Bikaner-Nagaur Basin of India emphasize the significance of studying and exploring the Neoproterozoic source rock potential in the southeastern part of Pakistan. This study evaluates the potential of the source rock in the Infracambrian rock sequence (Salt Range Formation) based on surface geochemical surveys, Rock–Eval pyrolysis, source biomarkers, geophysical characterization, and seismic inversion using machine learning for maturity index estimation. Core samples of Infracambrian rock were extracted for Rock–Eval pyrolysis and biomarker characterization. Additionally, 81 geomicrobial soil and gas samples were collected from the surface to explore the petroleum system and potential source rocks in the subsurface. Advanced interpretation techniques were used to investigate the origin and concentration of hydrocarbon gases at the surface, including Rock–Eval pyrolysis, thermal maturity, source biomarkers, and the environment of deposition of organic matter. The results show that the investigated samples are characterized by restricted marine clay devoid of sedimentary carbonate facies with thermal maturity in the early stage of the oil generation window. The seismic inverted maturity index profile demonstrates a reasonable correlation of thermal maturity with the biomarkers and Rock–Eval pyrolysis. Further scrutiny of the surface geochemical samples confirms the presence of higher concentrations of thermogenic C2–C4 hydrocarbons in the vicinity of anticlinal structures, suggesting the existence of an effective migration path along deep-seated faults to the surface. This study concludes that the Infracambrian rocks on the eastern flank of Pakistan are thicker, thermally mature, and have deep-seated structural closures, indicating a greater probability of heavy and light oil in this area than in the Bikaner–Nagaur Basin, India.

Modeling of hydrocarbons migration and accumulation processes in the Meso-Cenozoic complex of the Black Sea-Caspian Region

The article is devoted to the study of the processes of migration and accumulation of hydrocarbons in the Meso-Cenozoic complex of the Black Sea-Caspian region. The results of the modeling made it possible to study and model the processes of migration and accumulation of hydrocarbons in hydrocarbon systems in the Meso-Cenozoic complex of the Black Sea-Caspian region. All simulated petroleum systems are characterized by migration from the main reservoir, which lies directly above the simulated oil and gas source stratum, to the overlying ones. This is due to the peculiarities of the formation of sedimentary formations under conditions of alternating regressions and transgressions. The factor stimulating migration is the active tectonic regime of the studied sedimentary basins. Based on the modeling results, the conclusion about the wide development of hydrocarbon flow processes is consistent with the presence of multilayer deposits. It has been established that extended catagenetic zoning is typical for subsidence areas, which is due to the high rates of sedimentation and subsidence, and, accordingly, the large thickness of oil source deposits in the oil formation focus. Keywords: Black Sea-Caspian region; modeling; migration; accumulation; oil and gas source strata; deposit; sediments; organic matter.

ГЕОДИНАМІКА

Purpose. The objective of this study is the investigation of the Silurian-Lower Devonian (Lochkovian) carbonate-clay sedimentary complex of the southwestern slope of the East-European platform. Its formation was the result of a single cycle of geodynamic and sedimentary events in the lithological record of the southern continental margin of Baltica. Methodology. The study is based on well-logs correlation, lithological and geochemical investigations of core samples, and petrographic thin sections analysis. The obtained results were used to establish patterns of changes in the material composition of the studied strata in time and space in order to determine the basin development dynamics of the continental margin of the Eastern European platform southwestern slope in the Silurian-Early Devonian. Results. It is established that the formation of the carbonate-clay sequence represents a single sedimentary cycle and was the result of a complex of geodynamic, depositional and paleoclimatic events that took place on the Baltica southern continental margin. The Silurian period was characterized by intensive development of benthic organisms and reef structure formation in the proximal part of the basin and clay-carbonate muds enriched with dispersed organic matter in its distal part. In the Early Devonian, carbonate biogenic sedimentation continued throughout the basin. The carbonate maximum content (80–98%) proves the existence of the reef constructions in the basin sedimentary record. Lower values of carbonate content are characteristic of marls (40–55%) and biodetritic limestones (56–75%), which make up the main part of the Silurian sequence. There are no reef constructions in the section of the Lochkovian stage of Devonian, and the calcium carbonate content in the rocks varies from 45 to 83%. The content of CaCO3 in mudstones and calcareous mudstones of the Silurian varies from 5 to 15%. Originality. The applied complex of lithological, geochemical, geological-geophysical and paleogeographic investigations allowed studying the sedimentary basin dynamics in the Silurian-Early Devonian with the assessment of the possibility of participation of these strata in oil and gas hydrocarbons generation. Practical significance. The obtained results show that the carbonate-clay complex of sedimentary rocks of the Silurian and Lower Devonian (Lochkovian) of the studied region can be considered as a separate petroleum system, including source rocks, reservoir rocks and possible conventional and unconventional oil and gas accumulations.

Analysis of the Petroleum System Elements of the Amana Oil Field, East Abu Gharadig Basin, Western Desert, Egypt

Analysis of the Petroleum System Elements of the Amana Oil Field, East Abu Gharadig Basin, Western Desert, Egypt

Modelling of the burial and thermal histories of Jurassic-Cretaceous total petroleum system, Southeastern Tunisia

Modelling of the burial and thermal histories of Jurassic-Cretaceous total petroleum system, Southeastern Tunisia

Hydrocarbon Generation and Accumulation in the South Junggar Basin, Northwest China: Insights From Basin Modeling

The South Junggar foreland basin (SJFB) is characterized by fold-and-thrust deformation caused by the Cenozoic India–Tibet collision and uplift of the Tianshan Mountains. The tectonic deformation and hydrocarbon accumulation in this region show east-west, north-south, and vertical zoning. Four sets of source rocks are present in the basin, which are middle Permian, Middle–Early Jurassic, Early Cretaceous, and Paleogene in age. The various source rocks are vertically stacked and thus form a composite petroleum system. Due to differences in source rock distribution, hydrocarbon generation, and structural trap formation, the accumulation and distribution of oil and gas is spatially variable. In this study, we presented a detailed analysis of hydrocarbon generation and accumulation in the SJFB based on a combined basin modeling work both in 1D, 2D, and 3D single-well 1D modeling with measured temperature, and Ro data provide the suggested parameters, especially heat flow and erosion thickness, and then a simple 3D model was established based on the thickness maps of each formation and previous work on heat flow distribution. After 3D modeling, the results are rechecked with measured data and finally the source rock maturity map is obtained. By using the advanced “Block” function, the 2D modeling of complicated compressional structural sections has been successfully carried out. Four types of burial and thermal evolution history have been classified, which correspond to the different hydrocarbon phase and maturity. The heterogeneous distribution of oil and gas reflects the variable source rock distribution and maturity evolution, relative timing of hydrocarbon generation, and formation of structural traps. The timing of structural trap formation in the second and third row of anticlines was later than the main phase of hydrocarbon generation, which may explain the poor exploration outcomes in the SJFB. The result indicates that Jurassic and Cretaceous formations in the middle segment of the fold-and-thrust belt in the SJFB are the most favorable combination for hydrocarbon accumulations and have high potential for gas exploration.

Characteristics of Jurassic source rocks and oil and gas exploration direction in the piedmont zone between the south‐western Qaidam Basin and Altun Mountain

The Jurassic petroleum system in the piedmont zone between Qaidam Basin and Altun Mountain is rich in oil and gas resources. Based on the sedimentary environment, geochemical analysis, and distribution prediction of the Middle–Lower Jurassic source rocks in the piedmont zone between the south‐western Qaidam Basin and Altun tage region, the Jurassic oil and gas exploration potential in the area was systematically evaluated. The Jurassic source rocks in the study area are mainly coal, dark mudstone, and carbonaceous mudstone developed in the Lower Jurassic fan delta facies, as well as, oil shale, and mudstone in the Middle Jurassic of lacustrine facies, and coal measure strata of braided river delta facies. The thickness of Middle Jurassic source rocks is relatively thicker. Through restoration and weathered source rock samples analysis, the average TOC of the Middle Jurassic source rocks in the area can reach 4.19%, and the average chloroform bitumen “A” is 0.5915%, meeting the criteria for a good source stone. Every index is close to the Yuka Jurassic source rock, the highest quality found in the basin so far. At the same time, the distribution range of Jurassic source rocks in the study area is meticulously described through seismic facies identification and prediction analysis. Several Jurassic hydrocarbon generating centers in the area, such as Honggouzi ‐ Yueyashan, Nanyishan ‐ Xiaoliangshan, Pingxi, and Dafengshan, with thicknesses ranging from 200 to 400 m, indicating that the Jurassic source rocks have the material basis for large oil and gas fields formation.

Maturation study of vitrinite in carbonaceous shales and coals: Insights from hydrous pyrolysis

The presence of vitrinite in sedimentary rocks of post-Silurian age allows its reflectance to be used to estimate the thermal maturation of organic matter in petroleum systems. Increasing reflectance of vitrinite, which is primarily driven by aromaticity, depends primarily on the time and temperature attributes of its evolutionary pathway. This study evaluated carbonaceous shales proximal to coal measures and coal samples via isothermal hydrous pyrolysis (HP) to compare differences in the maturation pathways of vitrinite. Sample residues were analysed via vitrinite reflectance (VRo), geochemical screening tests (organic carbon and programmed temperature pyrolysis), and infrared spectroscopy. The study included samples from Indian and North American basins, to observe differences in vitrinite evolution with respect to enclosing mineral matrix, starting degree of aromaticity, organic matter types, stratigraphic age, and depositional environment. The organic content of HP residues shows an intuitive response to the thermal stress of HP, e.g., a general depletion of total organic carbon (TOC) content, pyrolyzate (S2), and hydrogen index with increasing HP temperature. Infrared proxies including C-factor and CH2/CH3 generally decrease with increasing thermal maturity indicating loss of O via CO2 generation and the thermal cracking of aliphatic organic matter. Tmax, production index (PI), and VRo show intuitive increasing values with respect to HP temperature. The least mature sample (0.48 ± 0.05% VRo) generally experienced the maximum change in these parameters during maturation, whereas the most mature sample (0.99 ± 0.06% VRo) generally showed the least change. This observation is consistent with higher kinetic barriers to reaction in more aromatic vitrinite which contains higher bond dissociation energies. Devolatilization of vitrinite during HP causes formation of gas evacuation vacuoles and contraction cracks in the vitrinite grains of both coal and carbonaceous shale. Similarities in vitrinite response to HP between coal and carbonaceous shale suggest that thermal evolution of the vitrinite maceral is principally controlled by inherent rate-limiting kinetic parameters related to its molecular structure. Whereas, the stratigraphic age, sedimentary environment, surrounding organic matter, lithology, and catalysis by mineral composition have less effect. To further improve our understanding of vitrinite aromatization and kinetic parameters, future studies of vitrinite reflectance thermal evolution with temperature should include coal and carbonaceous shale from the same stratigraphic section and extant woody tissue from modern vascular plants.

Explicit representation of natural fractures in modelling of fluid flow within source rocks – A Longmaxi Shale multiscale multiphysics unification case study

Natural fractures (NFs), ubiquitous in source rocks (SRs) commonly referred to as shale reservoirs, are posited to influence fluid flow. Quantification of post-stimulation flow and drainage architecture, consisting of hydraulic fractures (HFs) and NFs, have remained challenging. Quite often, NFs are implicitly accounted for, and when explicitly represented with discrete fracture networks (DFNs), the models are inadequately constrained. This study used well production, microseismic (MS) events, core plug permeability, core section images, borehole image (BHI) interpretations, core evaluation, and burial, tectonic and thermal history for the Longmaxi Shale (Sichuan Basin, China). Analytical solutions for transient linear flow, diagnosed from production data, led to linear flow parameters (LFPs) for scenarios with infinite and finite conductivity fractures. System permeability, in nandodarcy (nD) range, was derived using planar HF geometry validated by MS events. NF surface area multipliers (NFSAMs) stochastically accounted for the large surface area arising from reactivation of NFs. Subsequent matrix permeability, for a range of NFSAMs, was in pico- to sub-picodarcy (pD) range. NF rupture area derived from synthetic microseismicity and associated source properties constrained the representative NFSAM. For further validation, matrix permeability was derived using other techniques. One, laboratory-derived core plug permeability was stress-corrected for experimental and in situ conditions. Two, a core section image, with closely spaced sub-vertical and parallel NFs, guided analysis of flush production. Three, burial, tectonic and thermal history data was used in simplified basin and petroleum system modelling (BPSM) to account for petroleum expulsion and persistence of abnormal pore pressure over a geological timescale. Average matrix permeability from multiscale data and multiphysics assessments was scale- and play-independent. Lastly, DFN flow area and a simplistic architecture, comprising systematic NFs, allowed quantification of the average NF density for stimulated reservoir volume (SRV). Comparison of the aforementioned density with that from BHI interpretations and core evaluation offered a qualitative validation.

Geoscience Poster G3: Application of a probability model to detect unrecognised igneous intrusions in sedimentary basins

Poster G3 Mafic igneous intrusions are a common feature in extensional sedimentary basins, particularly those located at volcanic rifted margins, and are important in both exploration and development contexts due to their range of interactions with the petroleum system and their role as potential drilling hazards. Experience from a range of basins containing mafic igneous intrusions suggests that seismically resolvable intrusions are typically accompanied by a large number of intrusions that are too thin to be confidently identified and interpreted from seismic reflection surveys. The increased vertical resolution of wireline log data affords an opportunity to identify such sub-seismic-scale intrusions, though in many wells with full wireline suites igneous intrusions are often misidentified as sedimentary units, including felsic intrusions whose physical properties are more similar to sedimentary rocks. Here we apply a wireline-log-based probability model to well data from a number of basins. In previous applications, the model has proven highly effective in predicting the occurrence of carbonate cementation zones in sandstones in comparison to neural network approaches. We demonstrate its ability to predict the presence of igneous intrusions that were not previously identified by either seismic interpretation, or through the analysis of well-derived datasets. The broader application of this model to large suites of legacy data could lead to improved knowledge of the occurrence of intrusions in basins with implications for basin modelling and well planning. To access the poster click the link on the right. To read the full paper click here

Concurrent 17. Presentation for: Petroleum supersystems in the greater McArthur Basin, Northern Territory, Australia: prospectivity of the world’s oldest stacked systems with emphasis on the McArthur Supersystem

Presented on Wednesday 18 May: Session 17 This study assesses the prospectivity of the world’s oldest known stacked petroleum systems from the Proterozoic greater McArthur Basin (Northern Territory, Australia), which has immense potential to host both conventional natural gas and oil, in addition to shale-gas accumulations. The Mesoproterozoic succession of the Beetaloo Sub-basin and surrounding region hosts the Territory’s premier shale-gas play and is at an advanced stage of exploration for shale hydrocarbon plays. However, there is also potential for natural gas in older sedimentary packages, with flows and shows reported in underlying Paleoproterozoic successions. At the continent-scale, four regional petroleum supersystems are identified and described in order to provide a platform for consistent nomenclature at the sedimentary package and group level; in ascending stratigraphic order; these are the Paleoproterozoic Redbank and McArthur supersystems, the Paleoproterozoic–Mesoproterozoic Lawn Supersystem, and the Mesoproterozoic Beetaloo Supersystem. The Redbank and Lawn supersystems are newly named and defined, and the Beetaloo Supersystem is renamed from the former Urapungan Supersystem. Eight possible conventional natural gas plays and six shale-gas plays are documented within the McArthur Supersystem, which incorporates Glyde Package successions of the McArthur Basin and the Birrindudu Basin. Petroleum play concepts are also described from this supersystem to assist with assessing the potential for gas resources. A better understanding of the petroleum systems of the greater McArthur Basin is critical to the targeting of areas for geoscience data acquisition in order to facilitate the reduction of exploration search space; and it enables a more rigorous assessment of the potential for conventional and unconventional hydrocarbon resources at local (play) and regional scales. To access the presentation click the link on the right. To read the full paper click here

Concurrent 17. Presentation for: Stratigraphic framework and structural architecture of the Upper Cretaceous in the deep-water Otway Basin – implications for frontier hydrocarbon prospectivity

Presented on Wednesday 18 May: Session 17 Geoscience Australia has undertaken a regional seismic mapping study that extends into the frontier deep-water region of the offshore Otway Basin. This work builds on seismic mapping and petroleum systems modelling published in the 2021 Otway Basin Regional Study. Seismic interpretation spans over 18 000 line-km of new and reprocessed data collected in the 2020 Otway Basin seismic program and over 40 000 line-km of legacy 2D seismic data. Fault mapping has resulted in refinement and reinterpretation of regional structural elements, particularly in the deep-water areas. Structure surfaces and isochron maps highlight Shipwreck (Turonian–Santonian) and Sherbrook (Campanian–Maastrichtian) supersequence depocentres across the deep-water part of the basin. These observations will inform the characterisation of petroleum systems within the Upper Cretaceous succession, especially in the underexplored deep-water region. To access the presentation click the link on the right. To read the full paper click here

Geoscience Poster G5: Stratigraphic framework and structural architecture of the Upper Cretaceous in the deep-water Otway Basin – implications for frontier hydrocarbon prospectivity

Poster G5 Geoscience Australia has undertaken a regional seismic mapping study that extends into the frontier deep-water region of the offshore Otway Basin. This work builds on seismic mapping and petroleum systems modelling published in the 2021 Otway Basin Regional Study. Seismic interpretation spans over 18 000 line-km of new and reprocessed data collected in the 2020 Otway Basin seismic program and over 40 000 line-km of legacy 2D seismic data. Fault mapping has resulted in refinement and reinterpretation of regional structural elements, particularly in the deep-water areas. Structure surfaces and isochron maps highlight Shipwreck (Turonian–Santonian) and Sherbrook (Campanian–Maastrichtian) supersequence depocentres across the deep-water part of the basin. These observations will inform the characterisation of petroleum systems within the Upper Cretaceous succession, especially in the underexplored deep-water region. To access the poster click the link on the right. To read the full paper click here

Geoscience Poster G11: The Northwest Offshore Otway Basin Well Folio

Poster G11 The Otway Basin is a northwest–southeast trending rift basin which spans from onshore Victoria and South Australia into the deep-water offshore. The prospective supersequences within the basin are largely of Cretaceous age that host three possible petroleum systems (Austral 1, 2 and 3). While there is production from onshore depocentres, and the inboard Shipwreck Trough, the majority of the offshore basin remains underexplored. Recent regional studies have highlighted the need for further work across the underexplored parts of the basin and here we focus on the offshore northwest Otway Basin, integrating reinterpreted historical well data, newly acquired and recently reprocessed seismic data. This new Well Folio consists of composite logs and supporting data, which includes interpreted lithologies, petrophysical analyses, the analysis of historic organic geochemistry and organic petrology. In addition, updated well markers are provided based on seismic interpretation and new biostratigraphy in key wells. This integrated study provides the basis for renewed prospectivity assessment in the northwest offshore portion of the Otway Basin. To access the poster click the link on the right. To read the full paper click here

The Paleozoic petroleum system of the Molla-Bismil area (Diyarbakır Basin, Turkey) and source rock properties of Lower Silurian (Llandovery) organic-rich shale

The Molla-Bismil area is a petroleum province, which hosts predominantly Paleozoic oil fields in the foreland area of the Diyarbakır Basin. The Arpatepe, Bahar, Yeniev, and Çalıktepe fields are Paleozoic oil field discoveries in the Molla-Bismil area to-date and have consequently been the focus of considerable research. This significant breakthrough reveals that the deep-wells in the Molla-Bismil area have proven the existence of a Paleozoic petroleum system. Prospective source rocks are located stratigraphically above the upper part of the Bedinan Formation (Upper Ordovician) reservoir, near the base of the Dadaş Formation (Llandovery, Dadaş-1 member). The lithology of the lower part of the Dadaş-1 member, also known as hot shales in the Molla-Bismil area, are typified by organic-rich brownish-black colored shale containing bitumen and thin limestone beds. New well data assists with the regional definition and correlation of typical source rock properties within the Diyarbakır Basin. Subsurface stratigraphy was derived for several deep wells from the Molla-Bismil area and core or drill cuttings from the Çatak-1, Bahar-1, Göksu-1R and Çalıktepe-2 wells were studied and reviewed for lithological and geochemical information. The understanding and prediction of the geochemical characterization of the Lower Silurian (Llandovery) organic-rich shales relevant for hydrocarbon production are crucial for Turkey's fossil fuel supply. Based on new drilling data, we re-examined the properties of the Llandovery organic-rich shales in the Molla-Bismil region. This study brings together new and previously unpublished knowledge about the Paleozoic plays of SE Turkey.