Late Accumulation of Kunbei Area in Qaidam Basin

2013 ◽  
Vol 690-693 ◽  
pp. 3549-3552
Author(s):  
Hui Shi ◽  
Hui Li
Keyword(s):  
Seismic Data ◽  
Qaidam Basin ◽  
Scientific Evidence ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Tibet Plateau ◽  
Hydrocarbon Generation ◽  
Long Distance ◽  
Hydrocarbon Charging ◽  
The Tibet Plateau

This paper is aimed to find out the main reason of late accumulation of Kunbei area in Qaidam Basin using geochemistry and seismic data and to provide scientific evidence to the potential petroleum exploration in this area. Reservoirs in Kunbei fault terrace zone originate from petreoleum generated by source rocks of E32 in Zhahaquan depression after N23(about 5.2Ma), which means a charcteristic of hysteretic hydrocarbon generation. Brine inclusions shows two hydrocarbon charging periods.The first charging most likely happens at N1 and the second begins at N21,continuing to Q.Two deformaton stages exist in the study area due to the Tibet Plateau uplifting. The accumulations of first stage have been damaged after Middle N1. The reservoirs of Kunbei zone at present are almost orignated from E32 in depression. Above all,the primary cause of late accumulation is due to long-distance effects of the Tibet Plateau uplifting.

TECTONOSTRATIGRAPHY AND POTENTIAL SOURCE ROCKS OF THE BASS BASIN

2005 ◽  
Vol 45 (1) ◽  
pp. 601 ◽  
Author(s):  
J.E. Blevin ◽  
K.R. Trigg ◽  
A.D. Partridge ◽  
C.J. Boreham ◽  
S.C. Lang
Keyword(s):  
Seismic Data ◽  
Middle Eocene ◽  
Liquid Hydrocarbon ◽  
Source Rocks ◽  
Rift System ◽  
Complex Nature ◽  
Hydrocarbon Generation ◽  
Crustal Extension ◽  
Principal Source ◽  
Seismic Sequence Stratigraphy

A study of the Bass Basin using a basin-wide integration of seismic data, well logs, biostratigraphy and seismic/sequence stratigraphy has resulted in the identification of six basin phases and related megasequences/ supersequences. These sequences correlate to three periods of extension and three subsidence phases. The complex nature of facies relationships across the basin is attributed to the mostly terrestrial setting of the basin until the Middle Eocene, multiple phases of extension, strong compartmentalisation of the basin due to underlying basement fabric, and differential subsidence during extension and early subsidence phases. The Bass Basin formed through upper crustal extension associated with three main regional events:rifting in the Southern Margin Rift System;rifting associated with the formation of the Tasman Basin; and,prolonged separation, fragmentation and clearance between the Australian and Antarctic plates along the western margin of Tasmania.The final stage of extension was the result of far-field stresses that were likely to be oblique in orientation. The late Early Eocene to Middle Eocene was a time of rifttransition and early subsidence as the effects of intra-plate stresses progressively waned from east to west. Most of the coaly source rocks now typed to liquid hydrocarbon generation were deposited during this rift-transition phase. Biostratigraphic studies have identified three major lacustrine episodes during the Late Cretaceous to Middle Eocene. The lacustrine shales are likely to be more important as seal facies, while coals deposited fringing the lakes are the principal source rocks in the basin.

THE EVOLUTION OF THE BERNIER RIDGE, SOUTHERN CARNARVON BASIN, WESTERN AUSTRALIA:IMPLICATIONS FOR PETROLEUM PROSPECTIVITY

2004 ◽  
Vol 44 (1) ◽  
pp. 241 ◽  
Author(s):  
A.M. Lockwood ◽  
C. D’Ercole
Keyword(s):  
Seismic Data ◽  
Large Scale ◽  
Sedimentary Basins ◽  
Early Carboniferous ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Large Igneous Province ◽  
Satellite Gravity ◽  
Tectonic Events ◽  
Carnarvon Basin

The basement topography of the Gascoyne Platform and adjoining areas in the Southern Carnarvon Basin was investigated using satellite gravity and seismic data, assisted by a depth to crystalline basement map derived from modelling the isostatic residual gravity anomaly. The resulting enhanced view of the basement topography reveals that the Gascoyne Platform extends further westward than previously indicated, and is bounded by a northerly trending ridge of shallow basement, named the Bernier Ridge.The Bernier Ridge is a product of rift-flank uplift prior to the Valanginian breakup of Gondwana, and lies east of a series of small Mesozoic syn-rift sedimentary basins. Extensive magmatic underplating of the continental margin associated with this event, and a large igneous province is inferred west of the ridge from potential field and seismic data. Significant tectonic events that contributed to the present form of the Bernier Ridge include the creation of the basement material during the Proterozoic assembly of Rodinia, large-scale faulting during the ?Cambrian, uplift and associated glaciation during the early Carboniferous, and rifting of Gondwana during the Late Jurassic. The depositional history and maturity of the Gascoyne Platform and Bernier Ridge show that these terrains have been structurally elevated since the mid-Carboniferous.No wells have been drilled on the Bernier Ridge. The main source rocks within the sedimentary basins west of the Bernier Ridge are probably Jurassic, similar to those in the better-known Abrolhos–Houtman and Exmouth Sub-basins, where they are mostly early mature to mature and within the oil window respectively. Within the Bernier Ridge area, prospective plays for petroleum exploration in the Jurassic succession include truncation at the breakup unconformity sealed by post-breakup shale, and tilted fault blocks sealed by intraformational shale. Plays in the post-breakup succession include stratigraphic traps and minor rollover structures.

Petroleum potential of the offshore southern Carnarvon Basin—insights from new Geoscience Australia data

2011 ◽  
Vol 51 (2) ◽  
pp. 746
Author(s):  
Irina Borissova ◽  
Gabriel Nelson
Keyword(s):  
Seismic Data ◽  
Source Rocks ◽  
Magnetic Data ◽  
Long Distance ◽  
Potential Field Data ◽  
Petroleum Potential ◽  
Gravity And Magnetic ◽  
Gravity And Magnetic Data ◽  
Insight Into ◽  
Carnarvon Basin

In 2008–9, under the Offshore Energy Security Program, Geoscience Australia (GA) acquired 650 km of seismic data, more than 3,000 km of gravity and magnetic data, and, dredge samples in the southern Carnarvon Basin. This area comprises the Paleozoic Bernier Platform and southern part of the Mesozoic Exmouth Sub-basin. The new seismic and potential field data provide a new insight into the structure and sediment thickness of the deepwater southernmost part of the Exmouth Sub-basin. Mesozoic depocentres correspond to a linear gravity low, in water depths between 1,000–2,000 m and contain between 2–3 sec (TWT) of sediments. They form a string of en-echelon northeast-southwest oriented depressions bounded by shallow-dipping faults. Seismic data indicates that these depocentres extend south to at least 24°S, where they become more shallow and overprinted by volcanics. Potential plays in this part of the Exmouth Sub-basin may include fluvio-deltaic Triassic sandstone and Lower–Middle Jurassic claystone source rocks sealed by the regional Early Cretaceous Muderong shale. On the adjoining Bernier Platform, minor oil shows in the Silurian and Devonian intervals at Pendock–1a indicate the presence of a Paleozoic petroleum system. Ordovician fluvio-deltaic sandstones sealed by the Silurian age marine shales, Devonian reef complexes and Miocene inversion anticlines are identified as potential plays. Long-distance migration may contribute to the formation of additional plays close to the boundary between the two provinces. With a range of both Mesozoic and Paleozoic plays, this under-explored region may have a significant hydrocarbon potential.

The transformation effect of source rock-derived acidic fluid on carbonate reservoir from simulation experiments

2020 ◽  
Author(s):  
Qian Ding ◽  
Zhiliang He ◽  
Dongya Zhu
Keyword(s):  
Physical Properties ◽  
Source Rock ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
High Quality ◽  
Simulation Experiments ◽  
Deep Layers

<p>Deep and ultra-deep carbonate reservoir is an important area of petroleum exploration. However, the prerequisite for predicting high quality deep ultra-deep carbonate reservoirs lays on the mechanism of carbonate dissolution/precipitation. It is optimal to perform hydrocarbon generation-dissolution simulation experiments to clarify if burial dissolution could improve the physical properties of carbonate reservoirs, while quantitatively and qualitatively describe the co-evolution process of source rock and carbonate reservoirs in deep layers. In this study, a series of experiments were conducted with the limestone from the Ordovician Yingshan Formation in the Tarim Basin, and the low maturity source rock from Yunnan Luquan, with a self-designed hydrocarbon generation-dissolution simulation equipment. The controlling factors accounted for the alteration of carbonate reservoirs and dissolution modification process by hydrocarbon cracking fluid under deep burial environments were investigated by petrographic and geochemical analytical methods. In the meantime, the transformation mechanism of surrounding rocks in carbonate reservoirs during hydrocarbon generation process of source rock was explored. The results showed that: in the burial stage, organic acid, CO<sub>2</sub> and other acidic fluids associated with thermal evolution of deep source rocks could dissolve carbonate reservoirs, expand pore space, and improve porosity. Dissolution would decrease with the increasing burial depth. Whether the fluid could improve reservoir physical properties largely depends on calcium carbonate saturation, fluid velocity, water/rock ratio, original pore structure etc. This study could further contribute to the prediction of high-quality carbonate reservoirs in deep and ultra-deep layers.</p>

Differential diagenetic evolution and hydrocarbon charging of the tight limestone reservoir of the Da’anzhai Member in the central Sichuan Basin, China

2020 ◽  
Vol 8 (4) ◽  
pp. T1007-T1022
Author(s):  
Jiao Su ◽  
Zepu Tian ◽  
Yingchu Shen ◽  
Bo Liu ◽  
Qilu Xu ◽  
...  
Keyword(s):  
Sichuan Basin ◽  
Large Scale ◽  
Depositional Environments ◽  
Carbonate Reservoir ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Porosity Reduction ◽  
Hydrocarbon Charging ◽  
Pore Evolution ◽  
Central Sichuan Basin

The tight lacustrine carbonate reservoir of the Da’anzhai Member, Lower Jurassic Ziliujing Formation, in the central Sichuan Basin is a typical tight oil reservoir, and it is one of the crucial petroleum exploration targets in the Sichuan Basin. The porosity of the limestone ranges from 0.5% to 2%, and the permeability ranges from 0.001 to 1 mD. The Da’anzhai limestone experienced multiple diageneses, including compaction, cementation, dissolution, and recrystallization. Different diageneses occurred in the burial process due to the various fabrics and depositional environments, eventually forming distinct rock types; therefore, the pore evolution and hydrocarbon charging characteristics are inconsistent. In our research, there are two stages of major maturation and hydrocarbon expulsion in the source rocks of the Da’anzhai Member. The first large-scale expulsion of hydrocarbon is oil-based and gas-supplemented, whereas the second expulsion is dominated by gas. Hydrocarbon-filling characteristics are different in different types of reservoir rocks. Compared with the bioclastic grainstone and crystalline limestone, we have considered that the argillaceous shell packstone and bioclastic packstone deposited in the shallow and semideep lake environment still contain residual intergranular pores, which have not become fully compacted and are partly filled with hydrocarbons. The presence of hydrocarbon fluid hindered the secondary porosity reduction and was helpful for reserve space preservation.

scholarly journals Inversion tectonics: a brief petroleum industry perspective

2020 ◽  
Author(s):  
Gábor Tari ◽  
Didier Arbouille ◽  
Zsolt Schléder ◽  
Tamás Tóth
Keyword(s):  
Petroleum Industry ◽  
Structural Complexity ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Data Sets ◽  
Hydrocarbon Generation ◽  
Seismic Reflection Data ◽  
Reflection Seismic ◽  
Reflection Data ◽  
Well Data

Abstract. The concept of structural inversion was introduced in the early 1980s. By definition, an inversion structure forms when a pre-existing extensional (or transtensional) fault controlling a hangingwall basin containing a syn-rift or passive fill sequence subsequently undergoes compression (or transpression) producing partial (or total) extrusion of the basin fill. Inverted structures provide traps for petroleum exploration, typically four-way structural closures. As to the degree of inversion, based on large number of worldwide examples seen in various basins, the most preferred petroleum exploration targets are mild to moderate inversional structures, defined by the location of the null-points. In these instances, the closures have a relatively small vertical amplitude, but simple in a map-view sense and well imaged on seismic reflection data. Also, the closures typically cluster above the extensional depocentres which tend to contain source rocks providing petroleum charge during and after the inversion. Cases for strong or total inversion are generally not that common and typically are not considered as ideal exploration prospects, mostly due to breaching and seismic imaging challenges associated with the trap(s) formed early on in the process of inversion. Also, migration may become tortuous due to the structural complexity or the source rock units may be uplifted above the hydrocarbon generation window effectively terminating the charge once the inversion occurred. For any particular structure the evidence for inversion is typically provided by subsurface data sets such as reflection seismic and well data. However, in many cases the deeper segments of the structure are either poorly imaged by the seismic data and/or have not been penetrated by exploration wells. In these cases the interpretation of any given structure in terms of inversion has to rely on the regional understanding of the basin evolution with evidence for an early phase of substantial crustal extension by normal faulting.

THE PETROLEUM PROSPECTIVITY OF THE CLARENCE-MORETON BASIN IN NEW SOUTH WALES

1985 ◽  
Vol 25 (1) ◽  
pp. 15
Author(s):  
P. Ties ◽  
R.D. Shaw ◽  
G.C. Geary
Keyword(s):  
Source Rock ◽  
Seismic Data ◽  
New South ◽  
New South Wales ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
South Wales ◽  
Oil Generation ◽  
Single Fold ◽  
Coal Measures

The Clarence-Moreton Basin covers an area of some 28 000 km2 in north-eastern New South Wales and south-eastern Queensland. The basin is relatively unexplored, with a well density in New South Wales of one per 1600 km2. Since 1980, Endeavour Resources and its co-venturers have pursued an active exploration programme which has resulted in the recognition of significant petroleum potential in the New South Wales portion of the basin.Previous studies indicated that the Upper Triassic to Lower Cretaceous Clarence-Moreton Basin sequence in general, lacked suitable reservoirs and had poor source- rock potential. While exinite rich, oil-prone source rocks were recognised in the Middle Jurassic Walloon Coal Measures, they were considered immature for oil generation. Moreover, during the 1960's the basin acquired a reputation as an area where seismic records were of poor quality.These ideas are now challenged following the results of a new round of exploration which commenced in the New South Wales portion of the basin in 1980. This exploration has involved the acquisition of over 1000 km of multifold seismic data, the reprocessing of some 200 km of existing single fold data, and the drilling of one wildcat well. Over twenty large structural leads have been identified, involving trapping mechanisms ranging from simple drape to antithetic and synthetic fault blocks associated with normal and reverse fault dependent and independent closures.The primary exploration targets in the Clarence- Moreton Basin sequence are Lower Jurassic sediments comprising a thick, porous and permeable sandstone unit in the Bundamba Group, and channel and point-bar sands in the Marburg Formation. Source rocks in these and the underlying Triassic coal measures are gas-prone and lie at maturity levels compatible with gas generation. In contrast, it was established from the results of Shannon 1 that the Walloon Coal Measures are mature for oil generation and this maturity regime is now considered to be applicable to most of the basin in New South Wales.A consideration of reservoir and source rock distribution, together with structural trends across the basin in Petroleum Exploration Licences 258 and 259, has led to the identification of three prospective fairways, two of which involve shallow oil plays. Exploration of these fairways is currently the focus of an ongoing programme of further seismic data acquisition and drilling.

Maturity Evolution of the Cambrian Source Rocks in the Tarim Basin

2012 ◽  
Vol 622-623 ◽  
pp. 1642-1645
Author(s):  
Zong Lin Xiao ◽  
Qing Qing Hao ◽  
Zhong Min Shen
Keyword(s):  
Source Rock ◽  
Tarim Basin ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Mature Stage ◽  
Hydrocarbon Generation ◽  
Foreland Basins ◽  
Structural History ◽  
Depositional Age ◽  
Petroleum Basin

The Tarim basin is an important petroleum basin in China, and the Cambrian strata are the major source rock successions in the basin. Integrated the source rock depositional and structural history with its geochemical and thermal parameters, this paper simulates the evolution of the Cambrian source rocks with the software Basinview. The simulation result shows that the main hydrocarbon-generation centers of the Manjiaer sag in the Tabei depression and the Tangguzibasi sag in the Southwest depression are characterized by their early hydrocarbon generation, and in the late Ordovician depositional age, they reached dry gas stage. The Kuqa and Southwest depressions developed in the Cenozoic foreland basins made the Cambrian source rocks mature rapidly in the Cenozoic period. The source rock maturity in the Tarim basin now is characterized by high in the east and west and low in the middle, and most of the area is in the over-mature stage in the present. This study can provide available maturity data for the next petroleum exploration work.

scholarly journals Tectonosedimentary framework of Upper Cretaceous –Neogene series in the Gulf of Tunis inferred from subsurface data: implications for petroleum exploration

2017 ◽  
Vol 68 (2) ◽  
pp. 97-108 ◽  
Author(s):  
Wissem Dhraief ◽  
Ferid Dhahri ◽  
Imen Chalwati ◽  
Noureddine Boukadi
Keyword(s):  
Seismic Data ◽  
Upper Cretaceous ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Tectonic Activity ◽  
Petroleum Systems ◽  
Subsurface Structures ◽  
Gulf Of Tunis ◽  
Northeastern Tunisia ◽  
Well Data

Abstract The objective and the main contribution of this issue are dedicated to using subsurface data to delineate a basin beneath the Gulf of Tunis and its neighbouring areas, and to investigate the potential of this area in terms of hydrocarbon resources. Available well data provided information about the subsurface geology beneath the Gulf of Tunis. 2D seismic data allowed delineation of the basin shape, strata geometries, and some potential promising subsurface structures in terms of hydrocarbon accumulation. Together with lithostratigraphic data obtained from drilled wells, seismic data permitted the construction of isochron and isobath maps of Upper Cretaceous-Neogene strata. Structural and lithostratigraphic interpretations indicate that the area is tectonically complex, and they highlight the tectonic control of strata deposition during the Cretaceous and Neogene. Tectonic activity related to the geodynamic evolution of the northern African margin appears to have been responsible for several thickness and facies variations, and to have played a significant role in the establishment and evolution of petroleum systems in northeastern Tunisia. As for petroleum systems in the basin, the Cretaceous series of the Bahloul, Mouelha and Fahdene formations are acknowledged to be the main source rocks. In addition, potential reservoirs (Fractured Abiod and Bou Dabbous carbonated formations) sealed by shaly and marly formations (Haria and Souar formations respectively) show favourable geometries of trap structures (anticlines, tilted blocks, unconformities, etc.) which make this area adequate for hydrocarbon accumulations.

Observing Maturing Source Rocks on Seismic Reflection Data

Geophysics ◽  
2020 ◽  
pp. 1-56
Author(s):  
T. Matava ◽  
R. G. Keys ◽  
S. E. Ohm ◽  
S. Volterrrani
Keyword(s):  
Source Rock ◽  
Seismic Data ◽  
Pore Space ◽  
Regional Scale ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Maturity Model ◽  
Eastern Canada ◽  
Amplitude Response ◽  
Seismic Reflection Data

Hydrocarbon generation in a source rock is a complex, irreversible phase change that occurs when a source rock is heated during burial to change phase to a fluid. The fluid density is less than the kerogen density so in a closed or partially closed system the volume of the pore space occupied by fluids increases. Burial also increases the effective stress which leads to compaction and a significant reduction in porosity. The challenge of identifying source rocks on seismic data then becomes differentiating the smaller porosity increase due to hydrocarbon formation from the larger porosity decrease associated with burial. We use a calibrated rock physics model to show that Vshale and porosity data can be used to predict the compressional and shear wave velocities and the density in wells over large sedimentary sections, including a source rock of variable maturity. These well data and models show that the difference between an immature and mature source rock is an increase porosity (lower density) relative to compacting, non-source rock sediments. We use these results to identify a potential source interval in the Orphan Basin in Eastern Canada on 2D regional seismic data. We show that the full stack amplitude response of a maturing source rock is significant during the main phase of generation (0.2<transformation ratio<0.8) relative to surrounding sediments. Regional scale consistency of the amplitude response with the kerogen maturity model from an integrated basin simulator reduces exploration risk because the independence of the thermal model from the seismic amplitude response. Finally, combining the seismic response with the source rock maturity model provides insight into the likely kerogen kinetics. Most applications require regional data sets to capture the maturity window, however, applications are also possible around allochthonous salt where geometries can lead to local changes in heat flow.

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