Impacts of Neogene-Recent compressional deformation and uplift on hydrocarbon prospectivity of the passive southern Australian margin

The passive southern margin of the Australian continent, which formed following Cretaceous–Palaeogene separation from Antarctica, contains a rich record of Neogene–Recent compressional deformation and uplift. This deformation and uplift is manifested by reversal of displacement along syn-rift extensional faults, folding of mid–late Cenozoic post-rift sediments, and regional unconformities that can be traced for distances of up to 1,500 km along the margin. Palaeothermal data from onshore and offshore exploration wells indicate that erosion associated with deformation and uplift locally exceeds 1 km in the eastern Otway Basin. Both neotectonic palaeostress trends inferred from these structures and present-day stress orientations are consistent with northwest–southeast directed compression controlled to first-order by plate boundary forces. The critical role of the relative timing of trap formation and source rock maturation in controlling hydrocarbon prospectivity in the southern Australian margin is investigated by comparing two structures that formed during Neogene–Recent deformation in the Otway Basin: the Minerva and Nerita anticlines. While the Minerva Anticline hosts a major gas field (558 BCF GIP), the Nerita Anticline was found to be dry. A combination of apatite fission track analysis (AFTA), vitrinite reflectance (VR) and present-day temperature data show that all units intersected in Minerva–1 are presently at their maximum post-depositional temperatures, and are presently mature for hydrocarbon generation. In contrast, similar data collected from the preserved section at Nerita–1 indicate cooling from maximum post-depositional temperatures prior to formation of the Nerita Anticline in the late Miocene. Based on regional AFTA data, the underlying early Cretaceous source rocks probably reached maximum palaeotemperatures and ceased hydrocarbon generation during mid-Cretaceous uplift. These results indicate that areas of the southern margin that were deformed during the Neogene–Recent have the greatest potential to trap hydrocarbons where potential source rocks are presently at their maximum post-depositional temperatures.

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Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

Geofluids ◽

10.1155/2021/6020850 ◽

2021 ◽

Vol 2021 ◽

pp. 1-17

Author(s):

Haiping Huang ◽

Hong Zhang ◽

Zheng Li ◽

Mei Liu

Keyword(s):

Organic Geochemistry ◽

Vitrinite Reflectance ◽

Source Rocks ◽

East China ◽

Burial Depth ◽

Bohai Bay ◽

Hydrocarbon Generation ◽

Bohai Bay Basin ◽

Dongying Depression ◽

Hydrocarbon Maturation

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

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GEOLOGY, SOURCE ROCKS AND HYDROCARBON GENERATION IN THE CLARENCE-MORETON BASIN

The APPEA Journal ◽

10.1071/aj81001 ◽

1982 ◽

Vol 22 (1) ◽

pp. 5

Author(s):

A. R. Martin ◽

J. D. Saxby

Keyword(s):

Vitrinite Reflectance ◽

Source Rocks ◽

Geochemical Data ◽

Hydrocarbon Potential ◽

Hydrocarbon Generation ◽

Tectonic Events ◽

History Of ◽

Rock Eval ◽

Coal Measures ◽

Migration Pathways

The geology and exploration history of the Triassic-Cretaceous Clarence-Moreton Basin are reviewed. Consideration of new geochemical data ('Rock-Eval', vitrinite reflectance, gas chromatography of extracts, organic carbon and elemental analysis of coals and kerogens) gives further insights into the hydrocarbon potential of the basin. Although organic-rich rocks are relatively abundant, most source rocks that have achieved the levels of maturation necessary for hydrocarbon generation are gas-prone. The exinite-rich oil-prone Walloon Coal Measures are in most parts relatively immature. Some restraints on migration pathways are evident and igneous and tectonic events may have disturbed potentially well-sealed traps. Further exploration is warranted, even though the basin appears gas-prone and the overall prospects for hydrocarbons are only fair. The most promising areas seem to be west of Toowoomba for oil and the Clarence Syncline for gas.

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Analysis of Petroleum System for Exploration and Risk Reduction in Abu Madi/Elqar'a Gas Field, Nile Delta, Egypt

International Journal of Geophysics ◽

10.1155/2012/187938 ◽

2012 ◽

Vol 2012 ◽

pp. 1-10 ◽

Cited By ~ 5

Author(s):

Said Keshta ◽

Farouk J. Metwalli ◽

H. S. Al Arabi

Keyword(s):

Nile Delta ◽

Organic Matter Content ◽

Petroleum System ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Basin Modeling ◽

Burial History ◽

Gas Field ◽

Upper Miocene ◽

Migration Pathways

Abu Madi/El Qar'a is a giant field located in the north eastern part of Nile Delta and is an important hydrocarbon province in Egypt, but the origin of hydrocarbons and their migration are not fully understood. In this paper, organic matter content, type, and maturity of source rocks have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. Modeling of the empirical data of source rock suggests that the Abu Madi formation entered the oil in the middle to upper Miocene, while the Sidi Salem formation entered the oil window in the lower Miocene. Charge risks increase in the deeper basin megasequences in which migration hydrocarbons must traverse the basin updip. The migration pathways were principally lateral ramps and faults which enabled migration into the shallower middle to upper Miocene reservoirs. Basin modeling that incorporated an analysis of the petroleum system in the Abu Madi/El Qar'a field can help guide the next exploration phase, while oil exploration is now focused along post-late Miocene migration paths. These results suggest that deeper sections may have reservoirs charged with significant unrealized gas potential.

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3D-Basin Modelling of the Lishui Sag: Research of Hydrocarbon Potential, Petroleum Generation and Migration

Energies ◽

10.3390/en12040650 ◽

2019 ◽

Vol 12 (4) ◽

pp. 650 ◽

Cited By ~ 4

Author(s):

Jinliang Zhang ◽

Jiaqi Guo ◽

Jinshui Liu ◽

Wenlong Shen ◽

Na Li ◽

...

Keyword(s):

Source Rock ◽

Thermal Evolution ◽

Vitrinite Reflectance ◽

Three Dimensional ◽

Source Rocks ◽

Rock Properties ◽

Hydrocarbon Generation ◽

Hydrocarbon Accumulation ◽

Southeastern Part ◽

Petroleum Generation

The Lishui Sag is located in the southeastern part of the Taibei Depression, in the East China Sea basin, where the sag is the major hydrocarbon accumulation zone. A three dimensional modelling approach was used to estimate the mass of petroleum generation and accumulated during the evolution of the basin. Calibration of the model, based on measured maturity (vitrinite reflectance) and borehole temperatures, took into consideration two main periods of erosion events: a late Cretaceous to early Paleocene event, and an Oligocene erosion event. The maturation histories of the main source rock formations were reconstructed and show that the peak maturities have been reached in the west central part of the basin. Our study included source rock analysis, measurement of fluid inclusion homogenization temperatures, and basin history modelling to define the source rock properties, the thermal evolution and hydrocarbon generation history, and possible hydrocarbon accumulation processes in the Lishui Sag. The study found that the main hydrocarbon source for the Lishui Sag are argillaceous source rocks in the Yueguifeng Formation. The hydrocarbon generation period lasted from 58 Ma to 32 Ma. The first period of hydrocarbon accumulation lasted from 51.8 Ma to 32 Ma, and the second period lasted from 23 Ma to the present. The accumulation zones mainly located in the structural high and lithologic-fault screened reservoir filling with the hydrocarbon migrated from the deep sag in the south west direction.

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TECTONIC CONTROLS ON SEDIMENTATION AND MATURATION IN THE OFFSHORE NORTH PERTH BASIN

The APPEA Journal ◽

10.1071/aj88037 ◽

1989 ◽

Vol 29 (1) ◽

pp. 450 ◽

Cited By ~ 3

Author(s):

John F. Marshall ◽

Chao- Shing Lee ◽

Douglas C. Ramsay ◽

Aidan M.G. Moore

Keyword(s):

Seismic Reflection ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Late Permian ◽

Early Permian ◽

The West ◽

Australian Continent ◽

Multichannel Seismic Reflection ◽

Well Data ◽

Coal Measures

The major tectonic and stratigraphic elements of the offshore North Perth Basin have been delineated from regional BMR multichannel seismic reflection lines, together with industry seismic and well data. This analysis reveals that three sub- basins, the Edel, Abrolhos and Houtman Sub- basins, have formed as a result of three distinct episodes of rifting within the offshore North Perth Basin during the Early Permian, Late Permian and Late Jurassic respectively. During this period, rifting has propagated from east to west, and has culminated in the separation of this part of the Australian continent from Greater India.The boundaries between the sub- basins and many structures within individual sub- basins are considered to have been produced by strike- slip or oblique- slip motion. The offshore North Perth Basin is believed to be a product of transtension, possibly since the earliest phase of rifting. This has culminated in separation and seafloor spreading by oblique extension along the Wallaby Fracture Zone to form a transform passive continental margin.This style of rifting and extension has produced relatively thin syn- rift sequences, some of which have been either partly or completely removed by erosion. While the source- rock potential of the syn- rift phase is limited, post- rift marine transgressional phases and coal measures do provide adequate and relatively widespread source rocks for hydrocarbon generation. Differences in the timing of rifting across the basin have resulted in a maturation pattern whereby mature sediments become younger to the west.

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Hydrocarbon generation from Carboniferous-Permian coaly source rocks in the Huanghua depression under different geological processes

Petroleum Science ◽

10.1007/s12182-020-00513-2 ◽

2020 ◽

Vol 17 (6) ◽

pp. 1540-1555

Author(s):

Jin-Jun Xu ◽

Qiang Jin

Keyword(s):

Oil And Gas ◽

Vitrinite Reflectance ◽

Source Rocks ◽

Bohai Bay ◽

Hydrocarbon Generation ◽

Oil And Gas Exploration ◽

Geological Processes ◽

Light Oil ◽

Huanghua Depression ◽

Higher Temperature

AbstractNatural gas and condensate derived from Carboniferous-Permian (C-P) coaly source rocks discovered in the Dagang Oilfield in the Bohai Bay Basin (east China) have important implications for the potential exploration of C-P coaly source rocks. This study analyzed the secondary, tertiary, and dynamic characteristics of hydrocarbon generation in order to predict the hydrocarbon potentials of different exploration areas in the Dagang Oilfield. The results indicated that C-P oil and gas were generated from coaly source rocks by secondary or tertiary hydrocarbon generation and characterized by notably different hydrocarbon products and generation dynamics. Secondary hydrocarbon generation was completed when the maturity reached vitrinite reflectance (Ro) of 0.7%–0.9% before uplift prior to the Eocene. Tertiary hydrocarbon generation from the source rocks was limited in deep buried sags in the Oligocene, where the products consisted of light oil and gas. The activation energies for secondary and tertiary hydrocarbon generation were 260–280 kJ/mol and 300–330 kJ/mol, respectively, indicating that each instance of hydrocarbon generation required higher temperature or deeper burial than the previous instance. Locations with secondary or tertiary hydrocarbon generation from C-P coaly source rocks were interpreted as potential oil and gas exploration regions.

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Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

Geologica Carpathica ◽

10.2478/v10096-012-0026-2 ◽

2012 ◽

Vol 63 (4) ◽

pp. 335-342 ◽

Cited By ~ 3

Author(s):

Paweł Kosakowski ◽

Magdalena Wróbel

Keyword(s):

Organic Matter ◽

Thermal History ◽

Vitrinite Reflectance ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Thermal Maturity ◽

Burial History ◽

Se Poland ◽

Carpathian Foredeep ◽

Outer Carpathians

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

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Geochemistry and petrology of selected sediments from Bukit Song, Miri, Sarawak, Malaysia, with emphasis on organic matter characterization

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01275-2 ◽

2021 ◽

Vol 11 (10) ◽

pp. 3663-3688

Author(s):

Amin Tavakoli

Keyword(s):

Organic Matter ◽

Depositional Environment ◽

Vitrinite Reflectance ◽

Xrd Analysis ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Thermal Maturity ◽

Petroleum Potential ◽

Type Iv ◽

Two Samples

AbstractThe aim of this study is to provide a better understanding of the type of source input, quality, quantity, the condition of depositional environment and thermal maturity of the organic matter from Bukit Song, Sarawak, which has not been extensively studied for hydrocarbon generation potential. Petrological and geochemical analyses were performed on 13 outcrop samples of the study location. Two samples, having type III and mixed kerogen, showed very-good-to-excellent petroleum potential based on bitumen extraction and data from Rock–Eval analysis. The rest of the samples are inert—kerogen type IV. In terms of thermal maturity based on vitrinite reflectance, the results of this paper are akin to previous studies done in the nearby region reported as either immature or early mature. Ph/n-C18 versus Pr/n-C17 data showed that the major concentration of samples is within peat coal environment, whilst two samples were associated with anoxic marine depositional environment, confirmed by maceral content as well. Macerals mainly indicated terrestrial precursors and, overall, a dominance of vitrinite. Quality of the source rock based on TOC parameter indicated above 2 wt. % content for the majority of samples. However, consideration of TOC and S2 together showed only two samples to have better source rocks. Existence of cutinite, sporinite and greenish fluorescing resinite macerals corroborated with the immaturity of the analysed coaly samples. Varying degrees of the bitumen staining existed in a few samples. Kaolinite and illite were the major clays based on XRD analysis, which potentially indicate low porosity. This study revealed that hydrocarbon-generating potential of Bukit Song in Sarawak is low.

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GEOCHEMICAL TOOLS FOR EVALUATING PETROLEUM GENERATION IN MIDDLE PROTEROZOIC SEDIMENTS OF THE McARTHUR BASIN, NORTHERN TERRITORY, AUSTRALIA

The APPEA Journal ◽

10.1071/aj93051 ◽

1994 ◽

Vol 34 (1) ◽

pp. 692 ◽

Cited By ~ 4

Author(s):

Roger E. Summons ◽

Dennis Taylor ◽

Christopher J. Boreham

Keyword(s):

Vitrinite Reflectance ◽

Land Plant ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Strongly Correlated ◽

Petroleum Potential ◽

Petroleum Generation ◽

Early Palaeozoic ◽

Geochemical Analyses ◽

Rock Eval

Maturation parameters based on aromatic hydrocarbons, and particularly the methyl-phenanthrene index (MPI-1), are powerful indicators which can be used to define the oil window in Proterozoic and Early Palaeozoic petroleum source rocks and to compare maturities and detect migration in very old oils . The conventional vitrinite reflectance yardstick for maturity is not readily translated to these ancient sediments because they predate the evolution of the land plant precursors to vitrinite. While whole-rock geochemical tools such as Rock-Eval and TOC are useful for evaluation of petroleum potential, they can be imprecise when applied to maturity assessments.In this study, we carried out a range of detailed geochemical analyses on McArthur Basin boreholes penetrating the Roper Group source rocks. We determined the depth profiles for hydrocarbon generation based on Rock-Eval analysis of whole-rock, solvent-extracted rock, kerogen elemental H/C ratio and pyrolysis GC. Although we found that Hydrogen Index (HI) and the Tmax parameter were strongly correlated with other maturation indicators, they were not sufficiently sensitive nor were they universally applicable. Maturation measurements based on saturated biomarkers were not useful either because of the low abundance of these compounds in most Roper Group bitumens and oils.

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MATURATION PATTERNS IN THE PERTH BASIN

The APPEA Journal ◽

10.1071/aj78011 ◽

1979 ◽

Vol 19 (1) ◽

pp. 94 ◽

Cited By ~ 1

Author(s):

A. J. Kantsler ◽

A. C. Cook

Keyword(s):

Vitrinite Reflectance ◽

Upper Jurassic ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Geothermal Gradients ◽

The North ◽

Reservoir Conditions ◽

Igneous Activity ◽

Hydrocarbon Deposits ◽

Very High

Vitrinite reflectance data from wells drilled in the Perth Basin show that major variations exist in the pattern of rank distribution within the basin. Generally, rank gradients are low and near linear, but some wells show curvature of the rank profile in the Early Jurassic and Triassic parts of their sections. Curvature of the rank profile is generally associated with a shallow depth to basement, but the presence of very high ranks in parts of the Permian section on the Beagle Ridge suggests that a Permian to Jurassic thermal event associated with local igneous activity or the initiation of rifting, or both, may also be a controlling factor. Low, linear rank gradients from parts of the basin such as the Bunbury Trough and the thick Upper Jurassic sections of some of the deeper sub-basins are taken to indicate that low geothermal gradients have operated since the Permian,in the former instance and certainly since the Jurassic in the latter. Such conditions imply slow generation of hydrocarbons.Higher geothermal gradients and rank gradients in parts of the basin as in the north Dandaragan Trough and Vlaming Sub-basin imply enhanced hydrocarbon generation, particularly as calculated palaeotemperatures indicate that the advent of higher geothermal gradients is likely to have been relatively recent. Potential source rocks occur throughout the basin and provided that suitable structural and reservoir conditions can be delineated, the prospects of discovering more commercial hydrocarbon deposits are high.

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