One-dimensional Basin Modeling Research Articles

Timing of trap formation and petroleum generation in the northern East China Sea Shelf Basin

Basin modeling and cross-section restoration from the northern East China Sea Shelf Basin reveal the timing of trap formation and petroleum generation. Cross-section restoration suggest that extension started in the Late Cretaceous and was interrupted by inversion at the end of Miocene that created large anticline structures, providing numerous petroleum traps. One-dimensional basin modeling of the JDZ-VII-I well show that the main phase of oil generation in the synrift fluvial shales in the Jeju Basin occurred during the Early Oligocene–middle Miocene period, predating the regional inversion. Thus, potential for large oil accumulations in the southern part of the basin is probably limited. Most of the petroleum are likely to have flowed toward the basin margin as well as basin center until the Late Miocene because no structures were available to capture them. The formation of anticline structures overlapped and/or postdated the main phase of gas generation in the Jeju Basin. This is probably why the JDZ-VII-1 is gas-prone with the gas trapped mainly in the anticlinal structures formed by the tectonic uplift. The source rocks in the southwestern part of the Domi Basin are immature for petroleum generation.

Diagenetic controls on reservoir quality in Middle to Upper Jurassic sandstones in the South Viking Graben, North Sea

The deeply buried synrift play of the South Viking Graben is characterized by highly variable reservoir quality. An integrated approach incorporating petrophysics, petrography, and one-dimensional basin modeling methods was applied to investigate these variations. Analysis shows that average porosities below 4000 m (13,123 ft) (vertical depth below sea floor) range from approximately 5% to as much as about 25% in comparable quartz arenitic sandstones. From porosity-depth trends, three porosity categories can be recognized (normal-, low-, and high-porosity sandstones). Normal-porosity sandstones fall along the regional average porosity-depth trend. Low-porosity sandstones have been subject to extensive quartz cementation as a consequence of a higher degree of thermal maturity and plot below the regional porosity-depth trend. High-porosity sandstones plot above the regional porosity-depth trend. Here, quartz cementation has been inhibited by grain-coating microquartz, and thus porosity has been preserved. Hydrocarbon emplacement has previously been thought to have inhibited quartz cementation in the study area, but this study concludes that the reservoirs are mainly water-wet, allowing for continued quartz cementation despite the presence of hydrocarbon pore fluids. Predicting the distribution of microquartz-coated sandstones and the degree of thermal maturity is therefore fundamental for successful exploration in the deeply buried parts of the synrift play. This study presents a regional and stratigraphic framework for such predictions that may be incorporated into play models in the area.

Cross-section restoration and one-dimensional basin modeling of the Central Subbasin in the southern Kunsan Basin, Yellow Sea

The petroleum system of the Kunsan Basin in the Northern South Yellow Sea Basin is not well known, compared to other continental rift basins in the Yellow Sea, despite its substantial hydrocarbon potential. Restoration of two depth-converted seismic profiles across the Central Subbasin in the southern Kunsan Basin shows that extension was interrupted by inversions in the Late Oligocene-Middle Miocene that created anticlinal structures. One-dimensional basin modeling of the IIH-1Xa well suggests that hydrocarbon expulsion in the northeastern margin of the depocenter of the Central Subbasin peaked in the Early Oligocene, predating the inversions. Hydrocarbon generation at the dummy well location in the depocenter of the subbasin began in the Late Paleocene. Most source rocks in the depocenter passed the main expulsion phase except for the shallowest source rocks. Hydrocarbons generated from the depocenter are likely to have migrated southward toward the anticlinal structure and faults away from the traps along the northern and northeastern margins of the depocenter because the basin-fill strata are dipping north. Faulting that continued during the rift phase (∼ Middle Miocene) of the subbasin probably acted as conduits for the escape of hydrocarbons. Thus, the anticlinal structure and associated faults to the south of the dummy well may trap hydrocarbons that have been charged from the shallow source rocks in the depocenter since the Middle Miocene.

Geochemical modeling of sedimentary rocks in the central Hokkaido, Japan: Episodic deformation and subsequent confined basin-formation along the eastern Eurasian margin since the Cretaceous

Late Cretaceous to Paleogene tectonic episodes around the eastern Eurasian margin are described utilizing one-dimensional (1D) basin modeling technique on the basis of organic maturation; vitrinite reflectance and T max parameter values of the Rock-Eval pyrolysis. Fine-grained marine sediment of the Yezo Supergroup in central Hokkaido is one of the most extensive Cretaceous constituents along the plate margin. To evaluate organic maturation within the Yezo Supergroup, a surface section (Hakkin-zawa) and a deep borehole (MITI Yubari) were selected, from which quite different maturation trends were obtained. Notably low and constant maturation was suggested throughout the thick Hakkin-zawa section, and it was confirmed on the basis of various biomarker analyses. It requires anomalously rapid burial, probably related to thrust-stacking or large-scale slumping, followed by prompt tilting/exhumation event. In sharp contrast, Late Cretaceous strata in the MITI Yubari do not indicate coeval tectonic disturbances in a short period. A wider view of the ancient convergent margin suggests that deformation of the forearc propagated westward during the Cretaceous. High maturation levels in the uppermost thrust sheet around the MITI Yubari are optimized in 1D geochemical modeling on the assumption that a thick missing Paleogene unit has been eroded out as a result of thrust-forming contraction scheme emerged during the Neogene. A similar Cenozoic burial pattern is adopted for the once tilted and exhumed Hakkin-zawa section in order to match the present maturation levels. Although such an active subsidence of a ‘forearc’ is generally interpreted as an effect of the subduction erosion, heavy mineral composition of the shallow marine to fluvial Paleogene implies uplift and exhumation of ultramafic rocks to the east (trench-side). Thus the confined basin-formation in central Hokkaido is to be understood in a different tectonic framework that may reflect transcurrent motions on the plate margin.

An integrated evaluation of hydrocarbon charge and retention at the Griffin, Chinook, and Scindian oil and gas fields, Barrow Subbasin, North West Shelf, Australia

Paleo-oil-water contacts (paleo-OWCs) defined in eight wells from the Griffin, Chinook, and Scindian fields, Barrow Subbasin, Australian North West Shelf, are 47–147 m (154.2–482.3 ft) deeper than the current OWCs. The paleo-OWCs are deeper than the spillpoints separating the fields and are consistent with the existence of a single large paleo-oil accumulation. A plane of best fit projected through these paleo-OWCs describes an inclined surface with a northwesterly dip of approximately 1.5. Assuming that this paleo-OWC was horizontal at the time of charge, three-dimensional structural restoration was used to assess the trap geometry at that time and the impact of subsequent post-charge structuring. The paleo-OWC tilt is reduced to 0.6 by restoration to the middle Miocene, and by the base Tertiary, the paleo-OWC became over-rotated by 0.1. A horizontal paleo-OWC plane occurred some time between these periods and is broadly consistent with oil-charge estimates derived from fluid-inclusion paleotemperature data combined with one-dimensional basin modeling. The restored paleostructure and the approximate position of the paleo-OWC are consistent with the combined trap having initially been filled to spill. The bulk rock volume of the paleo-accumulation is more than 10 times larger than the current accumulation, indicating the loss of significant oil volumes as post-charge westerly tilting progressively reduced the trap capacity. Based on the current oil volumes (about 200 million bbl), nearly 2 billion bbl of oil was spilled from the trap by the relative shallowing of the eastern spillpoint. The region to the east and north of the Griffin area fields is lightly drilled, and remigration of such large volumes of oil to this area provides great incentive for future exploration. New targets are also inferred on the hanging wall of the main Griffin fault, which could represent bypassed pay.

Infill history of the Ulleung Basin, East Sea (Sea of Japan) and implications on source rocks and hydrocarbons

The Ulleung Basin in the East Sea (Sea of Japan) has experienced back-arc opening in the Miocene and partial closure since the middle Miocene. Uplift along the southern basin margin, caused by the back-arc closure, resulted in a series of anticlines and thrusts, providing large volumes of sediments into the basin. Mass-transport deposits dominated in the southern basin while turbidite and hemipelagic sedimentation prevailed in the northern basin. One-dimensional basin modeling shows that late postrift, early late-Miocene marginal-marine and prodeltaic sediments are buried too shallow to generate hydrocarbons. The main phase of oil generation in the synrift lacustrine and early-postrift marginal-marine facies (late Oligocene–early Miocene in age) beneath the southern basin margin occurred in the late early to early middle Miocene, predating the tectonic uplift. This significantly reduces the chances of large oil accumulations in the southern basin margin. The dominance of massive, non-uniform sediments in the southern basin, together with the lack of preferred avenues such as faults, are not favorable for the lateral migration of hydrocarbons, sourced possibly from basinal muds in the north, to the traps in the southern basin margin. Source rocks for the recently discovered gas in the southwestern shelf are probably the lacustrine and marginal-marine sediments that have been expelling gas at least since the late middle Miocene.

The petroleum system of the central Perija fold belt, western Venezuela

The timing of hydrocarbon migration relative to trap formation remains a factor in evaluating the exploration potential of the Perija fold belt on the west flank of the Lake Maracaibo Basin. Based on the data from this article, there is evidence of structural traps being filled by two oil migration events. At least four major events of deformation have been identified in the area from the Late Cretaceous to the Holocene. The first event is Late Cretaceous in age and characterized by compressional structures. The second event is characterized by extensional features and occurred from the Late Cretaceous to the middle Eocene. The third and fourth events are characterized by compressional structures that developed during the late Eocene and late Miocene-Holocene, respectively. Based on oil-oil and oil-source rock correlations and one-dimensional (1-D) basin modeling, two phases of oil generation and migration are proposed as responsible for oil accumulation in the central Perija fold belt. The first phase occurred from a kitchen of late Paleocene-late Miocene age located to the west-southwest of the study area. The second phase occurred during the middle Miocene-Holocene from a kitchen located to the east of the study area. The older kitchen is responsible for oil accumulations found in the Upper Cretaceous traps. The younger kitchen is responsible for possible oil accumulations in traps of both Cretaceous and Tertiary reservoirs located in the eastern part of the study area.

Simulation of oil expulsion by 1-D and 2-D basin modelling — saturation threshold and relative permeabilities of source rocks

Abstract In order for oil to accumulate in economic quantities, it first has to be generated and expelled from source rocks in sufficient quantities. In spite of long term efforts, the mechanism of oil expulsion from the source rocks is not completely understood. For modelling expulsion, the adoption of pressure-driven multiple-phase fluid flow governed by Darcy’s law is widely accepted. However, relative permeabilities for fine-grained source rocks, which is an essential parameter for this model, are very difficult to specify. The conventional reservoir-rock curve is obliged to be used for the modelling. Simplification of the relative permeability model is generally used for one-dimensional basin modelling. The 1-D model also requires substantial optimization of the key parameter, saturation threshold. Laboratory measurement of relative permeabilities for fine-grained rocks is very difficult, therefore, we carefully interpreted the analysed laboratory data on various sandstones to establish a relationship between relative permeability curves and pore geometry parameters, with a view to extrapolate the relationships developed in sandstones to fine-grained source rocks. It was found that the relative permeability curves, or irreducible water saturation are controlled by two factors ; grain size and clay content. Since the total surface area of the pore system becomes greater as the grain size decreases, we consider surface water adsorbed on the grain surface as a part of irreducible water. Since clay contains micro-porosity which cannot be displaced by oil due to high capillary pressure, we regard this to also play a role. Prediction of relative permeability curves for fine-grained rocks by both processes results in the curve with high irreducible water saturation. The new relative permeability curves were tested by both one-dimensional and two-dimensional basin modelling. Test results indicate that the new curves can reproduce expulsion efficiency, locations of accumulations and leaking through cap rock, which is consistent with actual observations.

Organic geochemistry and geohistory of the Triassic succession of Bjørnøya, Barents Sea

The Triassic outcrops of Bjørnøya provide an important reference for regional characterization of potential hydrocarbon source rocks of this age in the southwestern Barents Sea. The organic matter in both the Urd and Skuld Formations is dominated by woody and herbaceous material, with elevated contents of algal/bacterial organic matter present in the Urd Formation. Minor amounts of oil is likely to have been generated from these shales. These rocks have been deeply buried and are at a present-day thermal maturity corresponding to vitrinite reflectance of 1.2%, i.e. full realization of the kerogen's oil potential. One-dimensional basin modeling suggests that these Triassic rocks have been buried to near 5 km depth and expelled oil and gas during the Late Cretaceous to Early Tertiary. Bulk geochemical data show good agreement with visual observations of bitumen staining in thin sections. This staining has a biomarker distribution characterized by a homologous series of tricyclic terpanes. GC/MS/MS analyses showed this tricyclic series to extend from C 21 to C 46.

A new evaluation of palaeo-heat flows and eroded thicknesses for the Carboniferous Ruhr basin, western Germany

Palaeo-heat flows and thicknesses of eroded Carboniferous overburden in the coal-bearing Ruhr basin (western Germany) were estimated using one-dimensional basin modelling techniques. Thermal and burial histories for 11 localities were calibrated by comparing measured and calculated vitrinite reflectance data, based on the assumption of pre-tectonic maturation. In contrast to former studies, the kinetic EASY%R 0 approach applied for the calculation of vitrinite reflectance. Lopatin's TTI algorithm was used in addition for one well in order to demonstrate the impact of the selection of the algorithm for vitrinite reflectance calculation on the simulation results. Simulated palaeo-heat flows for the time of maximum burial (most probably in the Stephanian) range from 64 to 83 mW/m 2 and decrease towards the south. These heat flows are lower than values computed during earlier studies, but are still relatively high in comparison to recent foreland basins. The regional distribution of palaeo-heat flows indicates that the crust beneath the Ruhr basin was relatively thin and thickened towards the south at the end of the Carboniferous. After the Stephanian, 2200–3500 m of Carboniferous overburden were eroded. An observed southward increase in eroded thicknesses is caused by an uplift of the area studied, which decreased towards the north, at the end of the Variscan folding. Large thicknesses of deposited (and later eroded) Carboniferous sediments have to be postulated to explain the maturity data even along the present southern margin of the Ruhr basin. This indicates that the late Carboniferous sediments originally extended far to the south. Geological arguments suggest that the deposition of Carboniferous sediments in the entire Ruhr basin continued until the Stephanian.