HYDROCARBON GENERATION IN THE NORTHERN PERTH BASIN

1983 ◽  
Vol 23 (1) ◽  
pp. 64
Author(s):  
B. M. Thomas ◽  
S. A. Brown
Keyword(s):  
Vitrinite Reflectance ◽  
Lower Triassic ◽  
Land Plant ◽  
Lower Jurassic ◽  
Gas Condensate ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Reservoir Properties ◽  
Geothermal Gradients ◽  
Economic Significance

All known commercial hydrocarbon accumulatios in the Perth Basin, Western Australia, occur within the Dandaragan Trough or along its flanks. Land plant-rich source rocks are widely distributed throughout the Permian, Triassic and Jurassic sections of the basin. Hydrocarbon accumulations are mainly dry gas and gas/condensate, although secondary occurrences of light, waxy oil are also of economic significance. The Lower Jurassic Cattamarra Coal Measures provide both source and reservoir for gas/condensate accumulations in the central Dandaragan Trough (Walyering, Gingin). Gas at Dongara, Mondarra, Yardarino and the more recent discovery, Woodada, may have been generated from both the Lower Triassic and Permian, although there is some evidence that the Permian is the principal source. The associated thin oil legs encountered in parts of these fields and at Mt Horner is attributed to the oil-prone basal Kockatea Shale (Lower Triassic). Regional studies indicate a Neocomian uplift of the western flank of the Dandaragan Trough, centred on the Beagle Ridge. Vitrinite reflectance data suggest that the uplift and erosion of the Beagle Ridge was accompanied by higher geothermal gradients, up to 7.5°C/100 m in the Neocomian. Modern gradients of up to 5.0°C/100 m have been measured on the Beagle Ridge and possibly represent this waning geothermal anomaly. In contrast, low geothermal gradients are found in the Dandaragan Trough (around 2.5°C/100 m), and hydrocarbon generation presently occurs at great depths where sandstone reservoir properties are often inadequate for commercial production.

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

1994 ◽  
Vol 34 (1) ◽  
pp. 692 ◽  
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.

MATURATION PATTERNS IN THE PERTH BASIN

1979 ◽  
Vol 19 (1) ◽  
pp. 94 ◽  
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.

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

Geofluids ◽  
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.

scholarly journals Biomarkers and C and S Isotopes of the Permian to Triassic Solid Bitumen and Its Potential Source Rocks in NE Sichuan Basin

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-14 ◽  
Author(s):  
Chunfang Cai ◽  
Chenlu Xu ◽  
Wenxiang He ◽  
Chunming Zhang ◽  
Hongxia Li
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Lower Triassic ◽  
Source Rocks ◽  
Upper Permian ◽  
Solid Bitumen ◽  
Lower Silurian ◽  
High Maturity ◽  
Gas Fields ◽  
Extractable Organic Matter

The potential parent source rocks except from Upper Permian Dalong Formation (P3d) for Upper Permian and Lower Triassic solid bitumen show high maturity to overmaturity with equivalent vitrinite reflectance (ERo) from 1.7% to 3.1% but have extractable organic matter likely not contaminated by younger source rocks. P3d source rocks were deposited under euxinic environments as indicated by the pyrite δ34S values as light as -34.5‰ and distribution of aryl isoprenoids, which were also detected from the Lower Silurian (S1l) source rock and the solid bitumen in the gas fields in the west not in the east. All the solid bitumen not altered by thermochemical sulfate reduction (TSR) has δ13C and δ34S values similar to part of the P3l kerogens and within the S1l kerogens. Thus, the eastern solid bitumen may have been derived from the P3l kerogens, and the western solid bitumen was likely to have precracking oils from P3l kerogens mixed with the S1l or P3d kerogens. This case-study tentatively shows that δ13C and δ34S values along with biomarkers have the potential to be used for the purpose of solid bitumen and source rock correlation in a rapidly buried basin, although further work should be done to confirm it.

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

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.

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

Energies ◽  
2019 ◽  
Vol 12 (4) ◽  
pp. 650 ◽  
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.

DETERMINATION OF THE HYDROCARBON PROSPECTIVITY OF SEDIMENTS BY HYDROGENATION

1984 ◽  
Vol 24 (1) ◽  
pp. 222 ◽  
Author(s):  
E. J. Evans ◽  
B. D. Batts
Keyword(s):  
Liquid Hydrocarbon ◽  
Land Plant ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Content ◽  
Hydrocarbon Maturation ◽  
Significant Difference ◽  
Recent Developments ◽  
Exploratory Wells

Recent developments in hydrogenation procedures allow the liquid hydrocarbon potential and the total liquid hydrocarbon content of source rocks to be determined directly. In essence, mild controlled hydrogenation. without the cleavage of C-C bonds, converts the recognized hydrocarbon precursors in immature source rocks, i.e. the largely aliphatic acids, alcohols, esters, etc., into the parent alkanes. These alkanes, which have a distinctive composition, are easily collected and determined in toto by routine analytical processes. Thus hydrocarbon potentials are immediately revealed.Since the bulk of Australian crudes are of land plant (humic) origin, initial investigations have been largely concentrated on vitrinites and inertinites separated from Australian coals. These studies have shown that:the formation, on hydrogenation, of alkanes with a distinctive composition is an excellent guide to sediment maturity and to hydrocarbon potential; hydrocarbon generation, although not hydrocarbon maturation, is complete when the reflectance of vitrinite in contributing sediments approximates 0.65 per cent; and no significant difference exists between the hydrocarbon potentials and the hydrocarbon content of associated inertinites and vitrinites when the reflectance of the latter is in the range 0.3 to 1.2 per cent. These findings provide a guide to basin potentials and an explanation for the unexpected prospectivity of inertinite-rich Australian sediments.Results of applying this procedure to sediment samples from exploratory wells in the Gippsland and Cooper Basins have generally followed trends seen with coal samples and confirmed the value of the method in determining hydrocarbon potentials.

The coupled generation of organic acids and hydrocarbons during source rock maturation

2020 ◽  
Author(s):  
Jian Chen ◽  
Jie Xu ◽  
Zhenyu Sun ◽  
Susu Wang ◽  
Wanglu Jia ◽  
...  
Keyword(s):  
Organic Acids ◽  
Source Rock ◽  
Maximum Yield ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Pore Waters ◽  
Reservoir Properties ◽  
Type Iii ◽  
Short Period

<p><strong>Introduction: </strong>Organic acids which are commonly detected in oilfield waters, can partially enhance reservoir properties. Previous studies have suggested that cleavage of the oxygen-containing functional group in kerogen is a major source of organic acids. However, this cleavage is assumed to occur before the source rock enters the oil window. If this is correct, then these acids can dissolve only minerals in the source rocks. Presently, no detailed study of the generation of organic acids during the whole thermal maturation of source rocks has been conducted. It is unclear whether organic acids could migrate into reservoirs.</p><p><strong>Aim: </strong>This research simulated the thermal evolution of source rocks in order to build a coupled model of organic acid and hydrocarbon generation, and investigate if organic acids generated in source rocks can migrate into reservoirs.</p><p><strong>Methods: </strong>Three immature source rocks containing type I, II, and III kerogens were crushed to 200 mesh. These powders, along with deionized water, were sealed in Au tubes and heated to 220–360°C for 72 h (EasyRo 0.37-1.16%). All the run products, including organic acids, gas, and bitumen, were analyzed.</p><p><strong>Results: </strong>At all temperatures, the organic acids dissolved in the waters are composed of formate, acetate, propionate, and oxalate. Acetate is the major compound with a modal proportion of >83%. The maximum yield of total organic acids was from source rocks containing type I kerogen (31.0 mg/g TOC), which was twice that from source rocks containing type II and III kerogens (13.3–15.4 mg/g TOC). However, for the type I and II kerogen-bearing source rocks, the organic acids reached a maximum yield (EasyRo = 1.16%) following the bitumen generation peak (EasyRo = 0.95%). Organic acids from type III kerogen-bearing source rocks reached their maximum yield (EasyRo = 0.95%) before the source rock entered the gas window (EasyRo > 1.16%).</p><p><strong>Conclusions: </strong>Our data suggest that the generation of organic acids is coupled with the generation of oil from type I and II kerogen-bearing source rocks, but form earlier than gas from type III kerogen-bearing source rocks. As such, some organic acids dissolved in pore waters are possibly expelled from source rocks containing type I and II kerogen with oils, which can then migrate into reservoirs. Migration of organic acids into reservoirs from source rocks containing type III kerogen is also possible in some situations. For example, when a source rock is rapidly buried for a short period, such as in the Kuqa Depression, Tarim Basin, China, the generation interval of organic acids and gas is short. Both could be expelled outside and migrate upwards into reservoirs. In conclusion, organic acids derived from source rocks can contribute to reservoir alteration.</p>

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

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.

scholarly journals 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)

2012 ◽  
Vol 63 (4) ◽  
pp. 335-342 ◽  
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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