Petroleum System Modeling Research Articles

Coupling Relationship between Basin Evolution and Hydrocarbon Reservoirs in the Northern Central Myanmar Basin: Insights from Basin and Petroleum System Modeling

Coupling Relationship between Basin Evolution and Hydrocarbon Reservoirs in the Northern Central Myanmar Basin: Insights from Basin and Petroleum System Modeling

Comprehensive evaluation of the Paleogene lacustrine source rocks within the Bodong Sag, Bohai Bay Basin using kinetics-based petroleum system modeling

The hydrocarbon potential of the Bodong Sag remains unclear. Investigation and comprehensive evaluation of Paleogene lacustrine source rocks is essential to determine the exploration potential and direction. This study examined the Paleogene source rocks using organic geochemical methods, including total organic carbon (TOC), Rock-Eval pyrolysis, maceral composition, vitrinite reflectance (Ro), and kinetic analysis. For the first time in this study area, a three-dimensional (3D) kinetics-based petroleum system modeling approach was employed to reconstruct the burial history, thermal maturity, and hydrocarbon generation history of the source rocks. The resource mass was evaluated based on the calculated generation mass. Results indicate that the third member (E2s3) and first member (E3s1) of the Shahejie Formation are mainly Type II1 organic matter, exhibiting high generation potential. The third member of the Dongying Formation (E3d3) contains mixed Type II1 and II2 organic matter, with moderate potential. The E2s3 and E3s1 source rocks matured early, entering the oil window in the Early Oligocene (∼30.3 Ma) and Middle Oligocene (∼28 Ma), respectively, and are currently in the wet gas to dry gas stage. The E3d3 source rocks matured later, entering the oil window at the end of the Oligocene (∼24.6 Ma) and are currently in the late oil to the wet gas stage. Subsidence and burial have resulted in higher maturity in the southern subsag compared to the northern subsag, with the margins remaining in low maturity to immature stages. Resource estimates for the Bodong Sag source rocks are quantified at 8.33 × 108 t of oil and 1.68 × 1011 m3 of gas. E2s3, E3s1, and E3d3 contribute 41.62%, 33.95%, and 24.43% respectively, with E2s3 source rocks being the major contributor. The southern subsag, accounting for 76.92%, is the primary hydrocarbon generation kitchen. The significant increase in natural gas resources highlights the prospects for natural gas exploration in the Bodong area.

Unravelling the history of a complex hydrocarbon play through petroleum systems modelling – Catcher area development (CAD), UK Central North Sea region

Significant uncertainty exists with regards to the migration history of hydrocarbons in the Catcher Area Development (CAD) region, West Central Shelf, UK Central North Sea. In this study, petroleum system modelling is carried out to understand the pathways, timing and processes involved in hydrocarbons migration from the Jurassic Kimmeridge Clay to the injectite dominated sandstone reservoirs of the CAD region. The Cromarty sandstones are identified as the lateral carrier of hydrocarbons from the graben area to the CAD reservoirs. Out of the six CAD fields, five were charged along a fill spill chain. During the charging process, the CAD system was mostly seal limited, with significant hydrocarbon leakage into the overburden. Hydrocarbon migration and gas leakage in the region continues today. The present-day accumulations of the CAD region are spill limited suggesting the potential for more discoveries westward. This study provides an understanding of why gas chimneys are widespread in the CAD region and how the quality of hydrocarbons in the different fields relates to one another and those of the wider region. It also supports the presence of prospects further SW of the CAD region.

Quantifying the mineral magnetic signature of petroleum systems and their source rocks: a study on the Inner Moray Firth, UK North Sea

SUMMARY This study aims to expand on existing connections between magnetic minerals and hydrocarbons within petroleum systems. Previous studies have focussed on single-source petroleum systems whereas this study, for the first time, analyses a multi-source petroleum system to investigate potential correlations between different kerogen type source rocks and magnetic minerals. To do this, the study investigates the magnetic mineral characteristics of the Inner Moray Firth (IMF), UK North Sea, through room-, low- and high-temperature techniques, and correlates this to published basin and petroleum systems modelling results that show a three-source hydrocarbon mix. Magnetic mineral analysis identifies extensive evidence for magnetite, goethite and siderite, alongside more minor lepidocrocite and iron sulphides. Although we find that magnetite is ubiquitous within the IMF, its abundance is relatively low, and, in contrast, the relatively magnetically weak goethite is more likely the most abundant magnetic mineral throughout the IMF. In agreement with previous studies, we find magnetic enhancement at oil-water contacts (OWCs); however, here, we identify two different magnetic enhancement processes at OWCs in wells, which are dependent on the amount of sulphur available in the local environment. Wells with low levels of sulphur have increasing levels of magnetite towards the OWC, with the magnetic enhancement occurring at the top of the water-saturated section. Sulphur-rich environments display an increase in iron sulphides near the OWC at the bottom of the oil-saturated sediments. Additionally, we confirm the presence of siderite as indicator of upward vertical migration. Combining with petroleum system model predictions, we find direct links between iron hydroxide presence and Type I and II–III kerogen source rocks, and iron sulphide presence with Type II kerogen source rocks. This study shows the potential for further utilization of magnetic mineral analysis within hydrocarbon exploration and petroleum system definition.

Timing of hydrocarbon charge in the Axial Zone of the Eastern Cordillera, Colombia

The petroleum potential of onshore basins in Colombia has been partly controlled by the Andean Orogeny since the end of the Cretaceous. Its Axial Zone has at least one understudied active petroleum system with a rather low petroleum potential and few commercial medium to heavy oil accumulations, raising questions about how the Andean deformation influenced the petroleum system and the possible undiscovered accumulations. We examine the timing of this petroleum system in the Axial Zone through oil–source correlations and two 2D petroleum system models across the Boyacá and Soápaga faults based on cross-sections. Modelling reveals the direct control of deformation on generation–accumulation in the Axial Zone, where the Lower Cretaceous source rocks, due to high heat flows during the synrift phase, started generation so early (100 to 60 Ma) that no reservoirs or traps were yet available to allow hydrocarbon entrapment and accumulation. Equally, for the younger Upper Cretaceous source rocks, the tectonic inversion of the basin between 33 and 23 Ma along the Boyacá and Soápaga faults interrupted burial and the maturation in most parts of the basin, leaving only local pods of active source rocks where maturation continues today due to the tectonic overburden along the footwall of the Soápaga Fault. The latter is thus the major kitchen, contributing more than 50% of the liquid hydrocarbons trapped mainly in Upper Cretaceous and Paleocene sandstones. Hydrocarbons migrate upwards where biodegradation and water washing occurred in the near-surface, giving rise to the many tar sand occurrences in the Eocene sandstones.

New insights from petroleum systems modelling and magnetic analyses on the charge, fill and spill history of the Wytch Farm oil field, Wessex Basin, UK

Basin and petroleum systems modelling of the Wessex Basin, UK has been conducted to identify the maturation and migration events that charged the principal Bridport Sands and Sherwood Sandstone reservoirs at the Wytch Farm oil field. Modelling results have been compared with recent observations of magnetic enhancements at oil-water contacts (OWCs) and possibly paleocontacts (PCs) in Wytch Farm reservoirs, to assess the use of magnetic OWCs to help calibrate petroleum systems models and provide insights into the migration history of the Wessex Basin. The model predicts the Blue Lias source rock only reached maturity to the south of the Purbeck Fault, with hydrocarbon generation initiating in the Late Jurassic and peaking in the Late Cretaceous, requiring lateral migration to Wytch Farm using the Bridport Sands as the main carrier bed. Cross-fault and northward migration occurred through conduits at Creech, Bushey Farm and in offshore areas, which charged the principal structures at Wytch Farm. A ∼20 km wide Late Cretaceous juxtaposition between the Bridport Sands and Sherwood Sandstone in the hangingwall and footwall of the Purbeck Fault, respectively, led to the charging of the Sherwood Sandstone reservoir. A basin-wide Cenozoic easterly tilt of ≤1⁰ caused a westerly hydrocarbon remigration, has shifted the Bridport Sands and Sherwood Sandstone Wytch Farm structures to the west, and drastically reduced the size of Bridport Sands accumulations. There is a strong correlation between the predicted depths of Late Cretaceous and present-day OWCs with magnetic enhancements in drill cores. Multiple magnetic enhancements above the OWC at the Wareham oil field indicate the Cenozoic tilting event was periodic, forming multiple stable OWCs, with migration modelling suggesting a spill from Wytch Farm.

Modelling a foreland fold-and-thrust petroleum system: a Permian example in the NW Sichuan Basin, Southwest China

ABSTRACT Foreland thrust belts are globally significant areas for oil and gas exploration. These belts undergo unique tectonic activity, resulting in distinct variations in the accumulation of oil and gas. Studying the genetic evolution of deep oil and gas in these thrust belts is a crucial means of revealing the patterns of deep oil and gas accumulation. This study utilized a novel approach that combines reservoir geochemistry and basin simulation to determine the migration process of oil and gas in the foreland thrust fault belt of northwestern Sichuan Province. To achieve this goal, we established a thermal evolution model of lower Palaeozoic source rocks through organic chemical analysis. The balanced profile technique was used to determine the paleotectonic evolution pattern of the critical period in this area. Additionally, the mixed flow migration algorithm was employed to simulate the evolution of the Palaeozoic petroleum system. Through basin petroleum system modelling (BPSM), it was discovered that the bitumen found in the thrust nappe belt originated from the lower Cambrian strata. Furthermore, the gas reservoir in the hidden fault belt primarily migrated from the lower Cambrian strata and was also partially mixed with thermogenic gas from Permian source rocks. After establishing the genetic models of various tectonic belts in the study area, it became clear that there are notable differences in hydrocarbon accumulation within these belts. The BPSM results revealed that the oil present in the thrust nappe belt was generated in Lower Cambrian source rocks through early Indosinian hydrocarbon expulsion and continuous charging. The gas found in the thrust nappe belt was produced through the process of oil cracking in the deep reservoir located in the hidden front belt during the late Indosinian. The depth of the thrust nappe belt has helped to preserve hydrocarbon reservoirs. The natural gas present in the hidden fault belt primarily originates from lower Cambrian source rocks, which are combined with gas generated by oil cracking in lower Permian source rocks after the Yanshanian. Therefore, hydrocarbons accumulate deeply in the footwall of the thrust fault belt. The BPSM offers a fresh approach to hydrocarbon genetic models of thrust fault zones in the western Sichuan Basin, and it is beneficial for accurately evaluating the potential for deep hydrocarbon resources in comparable geological settings.

Shipwreck and Sherbrook supersequence regional gross depositional environments, offshore Otway Basin

The Shipwreck and Sherbrook supersequences together constitute the upper Cretaceous succession in the Otway Basin that was deposited during an extensional basin phase. In the Shipwreck Trough, where the upper Cretaceous succession is well explored, gas fields are hosted by the Shipwreck Supersequence (SS). Elsewhere, the upper Cretaceous interval is lightly explored, and the deep-water area is considered an exploration frontier. We present regional gross depositional environment (RGDE) maps for the LC1.1 and LC1.2 sequences of the Shipwreck SS, and the LC2 Sherbrook SS. Fluvial Plain, Coastal-Delta Plain and Shelf RGDEs were interpreted from wireline logs, cores, and seismic facies. The Fluvial Plain and Coastal-Delta Plain RGDEs are mostly restricted to the inboard platform areas and the inner Morum Sub-basin. The mud-prone Shelf RGDE is widespread across the deep-water Morum and Nelson depocentres. The extent of the Fluvial and Coastal-Delta Plain belts progressively increases up-section, imparting a regressive aspect to the succession, and delineating a large fluvial-deltaic complex in the north-west of the basin. Thick seal development across the greater Shipwreck Trough, potentially mature source rocks in the deep-water basin, and thick reservoir development in the hanging wall of growth faults in the inner Morum Sub-basin are insights derived from this study, and will inform area selection for detailed gross depositional environment mapping, formulation of new hydrocarbon and carbon dioxide storage plays, and inputs for petroleum systems modelling.

Petroleum systems analysis of the onshore Otway Basin, South Australia

An updated Petroleum Systems Model was built for the South Australian onshore Otway Basin, incorporating new seismic interpretation, seismic stratigraphy, core interpretations and a recent chemostratigraphy study. The Otway Basin is a divergent passive continental margin, with the Penola Trough the most significant hydrocarbon province discovered to date. Revision of the existing geochemistry database and seismic stratigraphy along with source rock model indicates potential good quality, liquids prone lacustrine source rocks are present in the Jurassic Casterton Formation (S0-P5) and the Early Cretaceous Basal Shale (McEachern Sand equivalent)/Lower Sawpit Shale (S1-P1/S1-P2). Gas prone source rocks are modelled in the Valanginian Upper Sawpit Shale (S1-P4/S1-P5) and Hauterivian Laira Formation (S1-P6–S1-P10). Modelling suggests liquid hydrocarbons were expelled from the Lower Sawpit Shale between 126 and 70 Ma, with the majority sourced from the Penola and Robe Troughs. Gas/condensate expulsion also took place up to 30 Ma from the Upper and Lower Sawpit Shale in the Penola and Robe Troughs. Gas is modelled to have been expelled from the Laira Formation in the Tantanoola Trough, between 100 Ma and present day.

INFLUENCE OF PLEISTOCENE GLACIATION ON PETROLEUM SYSTEMS AND GAS HYDRATE STABILITY IN THE OLGA BASIN REGION, BARENTS SEA

This study presents the results of a 2D numerical basin and petroleum systems model of the Olga Basin in the NW Barents Sea offshore northern Norway, a frontier exploration area in which there are abundant seafloor oil and gas seepages. The effects of Pleistocene ice sheet advances on rock properties and subsurface fluid migration in this area, and on seafloor hydrocarbon seepage, are not well understood. The 2D numerical model takes account of recurrent ice advances and retreats, together with related erosional and temperature effects, and investigates the influence of these parameters on fluid migration. Model results show that Pleistocene glaciations reduced the temperature in the sedimentary succession in the Olga Basin by up to 20 °C, for example in the uppermost Cretaceous and Jurassic sediments which underlie the seafloor down to a depth of 0.5 to 1 km. The decrease in temperature was in general predominantly related to the intensity of glacial erosion, which was set in this study to a depth of 600 m based on previous studies. Hydrocarbon fluids expelled from potential thermogenic source rocks of Carboniferous to Triassic ages on the SW margin of the Olga Basin migrated to the seafloor through permeable carrier beds. However, fluid migration to the surface in the NE of the study area took place along fault conduits. In a closed fault model scenario, only 0.3 Mt of hydrocarbons are modelled to have migrated along the 0.5 km wide model section; in a second scenario with partially open faults, about 22 Mt of hydrocarbons, representing about 11% of the total hydrocarbons generated by potential thermogenic source rocks in the study area, were lost to the surface during the Pleistocene. The potential for microbial methane generation in the Olga Basin was limited both during the Pleistocene and at the present day due to the significant reduction in temperature during glacial episodes, and due to the intense glacial‐related erosion of the Mesozoic to Cenozoic stratigraphy. During glacial stages, the gas hydrate stability zone beneath the ice sheet is modelled to have extended to a depth of up to 900 m for a pure methane composition, and to a depth of up to 1100 m for a possible thermogenic‐sourced mixed gas composition of 90% methane, 7% propane and 3% ethane. Gas hydrates with this mixed composition are modelled to have been stable in the Olga Basin during the last three glacial advances and into the present. These modelling results provide an insight into the key factors controlling the migration and surface leakage of hydrocarbon fluids in the Olga Basin region, and into the effects of glaciations on rock properties in a glaciated basin.

An innovative approach for investigation of overpressure due to hydrocarbon generation: a regional study on Kazhdumi formation, South-western Zagros Basin, Iran

Overpressure is always considered as a severe problem in the oil industry. Besides creating life risks through serious accidents while drilling, failure to correctly identify high-pressure intervals causes a significant increase in costs and prolongs the drilling process. Kazhdumi Formation in the Abadan Plain is considered as a high-pressure formation in several wells. Various reasons can cause overpressure problem. Hydrocarbon generation is one cause of abnormal pressure in source rocks. Understanding hydrocarbon generation potential can be a helpful approach since the Kazhdumi Formation is considered as a probable source rock in this area. In this paper, in order to better understand the problem of abnormal pressure in Kazhdumi Formation, geochemical concepts and tools have been applied. To that way, 1D petroleum system modeling of five wells was done, and the thermal maturity level of Kazhdumi Formation was determined and then, compared with drilling records. The results indicate that in wells where this formation has sufficient organic matter and has reached an early mature level, there is an abnormal pressure problem. Otherwise, this formation does not show abnormal pressure. Also, geochemical data are not available in all drilled wells, which makes impossible the assessing of hydrocarbon generation role. Therefore, petrophysical well logs (sonic (DT), neutron (NPHI), density (RHOB), spectral gamma ray (SGR), and resistivity (RES)) as well as 137 sets of geochemical data belonging to 13 wells from 7 oilfields in the Abadan Plain were used to predict geochemical indicators. Using artificial neural networks, geochemical data of a well in Abadan Plain were predicted. This selected well has a high-pressure problem in Kazhdumi Formation, but no geochemical data are available in this well. The results of predicted geochemical data show that the high-pressure phenomenon in this well may also be due to hydrocarbon generation. The precise understanding of the abnormal pressure, resulting from hydrocarbons generation, requires comprehensive studies and a full investigation of the studied area. However, the results of this paper help to predict approximately the behavior of the source rocks before drilling. Acquiring this overview will aid in reducing drilling hazards and costs.

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

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

Hydrocarbon Generation and Accumulation in the Eastern Kuqa Depression, Northwestern China: Insights from Basin and Petroleum System Modeling

The eastern Kuqa Depression in the northern Tarim Basin, NW China, is rich in oil and gas. However, recent exploration has been hindered by a lack of knowledge on the evolution of the petroleum system. To address this, we conducted hydrocarbon generation and accumulation modeling using both the 2Dmove and PetroMod2017 software for a complex tectonic extrusion section in the Kuqa Depression. The results show that the source rocks in the northern slope zone became mature quite early at around 170 Ma, but the thermal maturity evolution stagnated subsequently because of tectonic extrusion and uplift. The source rocks in the central anticline zone, the southern slope zone, and the deep sag zone were of overall low maturity during the Jurassic to Paleogene but rapidly became mature to highly mature with the deposition of the Neogene Jidike and Kangcun formations. The main hydrocarbon generation periods are in the late Neogene and Quaternary, and the main hydrocarbon generation stratum is the lower Jurassic Yangxia formation. The amount of cumulative hydrocarbon generation gradually increases for carbonaceous mudstone, mudstone, and coal source rocks. Sourced from source rocks mainly in the northern slope zone, oil and gas migrated to anticlinal traps along sandstone transport layers and faults. Recent discoveries, such as the Tudong-2 gas field in the central anticline zone, underscore the richness of this region in petroleum resources. Some gas fields were also predicted in lithologic traps in the southern slope zone and the deep sag zone, as well as in fault-related traps in the northern part of the northern slope zone.

Reconstruction of palaeo‐oil reservoirs in the ultra‐deep and over‐mature Sinian Dengying Formation of the Central Sichuan Basin: Insights from basin and petroleum system modelling

Ultra‐deep Sinian carbonate rocks are rich in natural gas, and the Deng‐4 Member of the Central Sichuan Basin has been shown to have an extremely high degree of thermal evolution. They are characterized by dry gas produced due to the thermal cracking of palaeo‐oil reservoirs (PORs). The distribution of PORs as materials for the formation of cracked gas reservoirs remains unclear. The complex multistage evolution process and limited drilling data make it challenging to precisely and systematically recover a range of PORs. Based on basin and petroleum system modelling (BPSM), the bottom‐up migration and accumulation method was used to investigate the distribution of PORs. Research shows that the PORs in the Sinian Deng‐4 Member were mainly formed in the Early–Middle Triassic under the mixed contribution of Cambrian and Sinian source rocks, and the coupling of palaeostructural and trap settings controlled its accumulation. Generally, the distribution of PORs can be divided into two categories: one is located at the core of the uplift zone and is controlled by structural‐stratigraphic composite traps, whereas the other is controlled by a series of lithologic traps formed in the slope area. Sensitivity analysis showed that the distribution patterns of the PORs were mostly related to the facies conditions (physical characteristics) of the reservoirs. The widely distributed PORs provide necessary and sufficient material conditions for the formation of cracked Sinian gas reservoirs in the Central Sichuan Basin, and the North Slope area has great potential for natural gas exploration in the future.

The impact of Oligo-Miocene basaltic intrusions on the petroleum system in Gulf of Suez rift basin, Egypt: new insights into thermal maturity and reservoir quality

In recent years, the petroleum industry has prioritized the exploration of new and unconventional petroleum reservoirs. As a result, this study assessed the significance of basaltic intrusions from two key aspects: their impact on the thermal maturity of pre-rift source rocks and their potentiality as reservoirs. The present study attempts to integrate surface field investigations of basaltic dykes in Wadi Nukhul and Wadi Matulla as surface analogs with petroleum system modeling of pre-rift source rocks containing subsurface basaltic intrusions in the Abu Rudeis-Sidri field. Therefore, the fracture networks were observed in Wadi Nukhul and Wadi Matulla, suggesting that both the basaltic dykes and host rocks have interconnected fractures, which is critical for a high-quality reservoir of the dykes and efficient oil expulsion. As a result, the analysis of burial history, temperature, maturity, generation, transformation ratio, and expelled oil quantity revealed a significantly high value for basaltic intrusions. Moreover, the Abu Rudeis-Sidri field had a good petroleum system with thermally mature source rocks by basaltic intrusions. Furthermore, the fractured basaltic intrusions presented a high-quality oil reservoir well-sealed by the thick Rudeis Formation. Oil production has doubled since the discovery of this reservoir. This study introduces a novel approach to understanding the distribution pattern of basaltic intrusions in subsurface and surface analogs, which can serve as a model for exploring new potential unconventional basaltic reservoirs in the Gulf of Suez rift basin.

A Fresh Look at the South Australian Onshore Otway Basin (Insights from Dem's Petroleum Systems Model Project)

The Otway Basin is one of the best known Mesozoic rift basins that span the southern coastline of Australia and has both on and offshore gas production and oil discoveries. 104 petroleum and 6 geothermal wells have drilled since the 1890s. In 1987 Katnook 1 discovered economic gas in the Penola Trough (the most significant hydrocarbon province in the SA part of the basin to date), further drilling led to more discoveries and construction of a processing plant.

Utility of fluid inclusion paleo-temperature in petroleum system modelling: A case study from western offshore, India

The paleo-temperature (Th) data from fluid inclusions are utilized for thermal history modelling using PetroMod software. Generally, bottom hole temperature (BHT) and vitrinite reflectance (Ro) measurements are widely used in petroleum system modelling (PSM) in the oil industry for calibration purposes. Th representing the minimum temperature of fluid entrapment estimated from fluid-inclusion study provides extra support to build the thermal models for PSM. Fluid inclusion parameters along with Rock-Eval pyrolysis analysis have been used to predict the maturity of oil in terms of API gravity as well as the maturity of source rocks respectively. Two exploratory wells RV-1 (Mumbai Offshore Basin) and KK4C-A-1 (Kerala-Konkan Offshore Basin), India were examined and the Th from most of the fluid inclusions of wells RV-1 and KK4C-A-1 fell in the oil window range of 60–140 °C suggesting thermal conditions favourable for oil generation in both of the wells. Th of coeval aqueous inclusions along with the Hydrocarbon Fluid inclusions (HCFIs) was used to calibrate PSM. Vital parameters show that source rocks of well RV-1 are mature and that of well KK4C-A-1 are immature. Two sets of PSM are created in terms of generation and expulsion for the dry wells RV-1 and KK4C-A-1 and calibrated each well using fluid inclusion Th and BHT. From the fluid inclusion analysis method, it is evident that hydrocarbon generation happened in both wells and the paleo-temperature indicates that the formations of both wells were subjected to temperatures in the oil window range, even though it was designated as dry wells in the present scenario. The present study highlights the application of fluid inclusion paleo-temperature (Th) during calibration instead of commonly used methods. We could obtain desirable and accurate data output from PSM using Th calibration.

Relationship between fluorescence and IR parameters of oil inclusions and crude oils in the Dongpu Depression (Bohai Bay Basin, China)

The Dongpu Depression is an important petroliferous basin in China with abundance of hydrocarbons. The fluorescence characteristics of inclusion oils and their relationship with the present-day produced crude oils have never been systematically studied in the basin scale. This knowledge can further clarify ambiguities in petroleum system modeling and support exploration efforts in the area. To this end, core samples and crude oils were collected from the Shahejie Formation (Paleogene) in the Dongpu Depression to perform fluorescence and infrared spectroscopy from the source rock and the reservoir. Results show that the fluorescence characteristics of oil inclusions in the source rocks are consistent with oil inclusions in the reservoirs in the northern part of the depression, showing blue, green, yellow and orange fluorescence colors; whereas orange fluorescence is absent in the southern part in inclusions. Moreover, lack of a robust relationship between λmax and QF-535 suggests crude oils have gone through secondary alterations towards becoming heavy oil. Herein, comparison between the IR (CH2/CH3) and fluorescence parameters (λmax and QF-535) illustrates that CH2/CH3, although is suitable for organic matter thermal maturity assessment, cannot be directly applied to the expelled oils. Moreover, the occurrence of orange fluorescing oils in the horsts can be accounted for a higher hydrocarbon potential in these areas. Additionally, establishing a clear relationship between fluorescence and IR parameters failed in certain strata or structural unit, proving a complex tectonic setting of the depression. Overall, this study reveals the geologic nature of the Dongpu Depression is very complicated, which means additional analytical studies to resolve the oil-source correlation problem, in particular, would be necessary.

Whole petroleum system and hydrocarbon accumulation model in shallow and medium strata in northern Songliao Basin, NE China

Based on the oil and gas exploration practice in the Songliao Basin, combined with the latest exploration and development data such as seismic, well logging and geochemistry, the basic geological conditions, oil and gas types and distribution characteristics, reservoir-forming dynamics, source-reservoir relationship and hydrocarbon accumulation model of the whole petroleum system in shallow and medium strata in the northern part of Songliao Basin are systematically studied. The shallow–medium strata in northern Songliao Basin have the conditions for the formation of whole petroleum system, with sufficient oil and gas sources, diverse reservoir types and well-developed transport system, forming a whole petroleum system centered on the source rocks of the Cretaceous Qingshankou Formation. Different types of oil and gas resources in the whole petroleum system are correlated with each other in terms of depositional system, lithologic association and physical property changes, and they, to a certain extent, have created the spatial framework with orderly symbiosis of shallow–medium conventional oil reservoirs, tight oil reservoirs and shale oil reservoirs in northern Songliao Basin. Vertically, the resources are endowed as conventional oil above source, shale oil/tight oil within source, and tight oil below source. Horizontally, conventional oil, tight oil, interlayer-type shale oil, and pure shale-type shale oil are developed in an orderly way, from the margin of the basin to the center of the depression. Three hydrocarbon accumulation models are recognized for the whole petroleum system in northern Songliao Basin, namely, buoyancy-driven charging of conventional oil above source, retention of shale oil within source, and pressure differential-driven charging of tight oil below source.

Petroleum system analysis and thermal evolution of the deepwater NW Borneo fold-thrust belt

The generation of hydrocarbons in source rocks can lead to overpressure, which can support development of detachments and the deformation of sedimentary rocks. In turn, the deformation of rock units by e.g., large-scale overthrusting can lead to tectonic-driven burial. Tectonic-driven burial can generate overpressure, which in turn can influence the petroleum system. In fold-thrust belts, an integrated understanding of both, the tectonic and the petroleum systems is important for understanding the potentially complex interaction of faulting, folding and fluid geochemistry. This study combines structural restoration and basin-modeling techniques to provide a comprehensive view of the fold-thrust system offshore northwest Borneo.In the deepwater region offshore northwest Borneo a major fold-thrust belt is present. The thrust belt is characterized by a mix of gravity-driven folding and faulting in a southwestern domain, and deep-seated crustal deformation in a northeastern domain. Oil and gas preferentially accumulated in thrust-top anticlines. The NW Borneo fold-thrust belt has a low taper angle; likely related to fluid overpressure along the basal detachment. The basin models presented in this study are based on an integration of regional 3D seismic-reflection interpretation, borehole analysis and 2D kinematic restoration. 2D petroleum systems modeling shows oil and gas generation and expulsion from Middle Miocene coaly source rocks since the Late Miocene, migration of the hydrocarbons through carrier beds and faults, and the accumulation of oil and gas in thrust-hangingwall anticlines. Vertical gas leaks modeled are comparable with gas clouds observed on 3D seismic-reflection data. The risk of biodegradation was estimated for reservoirs shallower than 1000–1500 m, and their burial is influenced by uplift due to thrusting. Combined tectonic and thermal modeling of the fold-thrust belt indicates the initiation of shortening at the time when the maturation of the source rock at the basal detachment was within the oil window. The timing of the maximum shortening rate, however, exhibits regional variations across the fold-thrust belt. In the gravity-driven fold thrust system in the southwest, the primary control on the peak of shortening is the maturation of the source rock at basal detachment level (gas window). In contrast, the peak of shortening in the northeast with the deep-seated crustal-driven system is interpreted as being primarily controled by the intensity and timing of the external stress.