PETROLEUM GEOLOGY OF THE MERLINLEIGH SUB-BASIN, WESTERN AUSTRALIA

1985 ◽  
Vol 25 (1) ◽  
pp. 190
Author(s):  
I.G. Percival ◽  
P.M. Cooney
Keyword(s):  
Vitrinite Reflectance ◽  
Early Carboniferous ◽  
Organic Content ◽  
Source Rocks ◽  
Early Permian ◽  
Potential Reservoir ◽  
Hydrocarbon Sources ◽  
The 1960S ◽  
Group Play ◽  
Exploration Activity

Esso's recent drilling program in the Merlinleigh Sub-basin, onshore Carnarvon Basin, represents the culmination of the first phase of concerted exploration activity in the area since the WAPET era of the 1960s. The region is unusual among Australian petroleum provinces in having excellent exposures of reservoir, source and seal rocks of Palaeozoic age. While both Esso wells (Burna 1 and Gascoyne 1) failed to encounter hydrocarbons in the primary Wooramel Group play, encouraging potential still exists. The reservoir in the Wooramel Group play is the Early Permian Moogooloo Sandstone, a fluviodeltaic to nearshore sheet-sand facies with porosities to 23 per cent and permeabilities in excess of 100 millidarcys. Likely hydrocarbon sources are siltstones in the overlying Byro Group, with total organic carbon contents averaging 3 per cent, and calcilutites in the subjacent Callytharra Formation with similar organic content. Locally, the Jimba Jimba Calcarenite Member (Billidee Formation) and the Cordalia Sandstone also provide rich source units. The least certain aspects of the Early Permian play are fault and top seal, and reservoir quality at depth. Notwithstanding the relatively shallow depths to source strata in the area, vitrinite reflectance analyses from drill cores indicate that maturation is attained as shallow as 900 m on the folded and faulted western margin of the sub-basin, and at an approximate depth of 1200 m in the depocentre beneath the Kennedy Range. This can be related to high regional heat flow, and to erosion of some 1500-2000 m of sediments prior to the regional Early Cretaceous transgression.Older plays which have been identified in the area remain to be adequately evaluated. Potential reservoir sands are present in the Silurian Tumblagooda Sandstone, the Middle and Late Devonian Nannyarra and Munabia Sandstones, and the Early Carboniferous Williambury Formation. Possible source rocks include carbonates of Middle Devonian and Early Carboniferous age. One of the objects of current research has been to locate areas where seal, provided by the glacigene Lyons Formation of Late Carboniferous-Early Permian age, is sufficiently thin to permit economic drilling.

scholarly journals Geology and transitional shale gas resource potentials in the Ningwu Basin, China

2018 ◽  
Vol 36 (6) ◽  
pp. 1482-1497
Author(s):  
Qiang Xu ◽  
Fengyin Xu ◽  
Bo Jiang ◽  
Yue Zhao ◽  
Xin Zhao ◽  
...  
Keyword(s):  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Sedimentary Environment ◽  
Organic Content ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Lower Paleozoic ◽  
Gas Source ◽  
Average Porosity ◽  
Pore Types

We analyzed the tectonic evolution characteristics, sedimentary environment, geochemical characteristics, petrological characteristics, and gas-bearing properties of three mudstone sections of the Lower Paleozoic in Ningwu Basin, NE China, and determined the geologic characteristics and resource potential of the transitional facies shale gas. Geochemical analysis of the organic carbon content, kerogen macerals, and vitrinite reflectance of the shale samples showed that the total organic content was generally over 2.0%, the main organic type was type III, and the vitrinite reflectance values (Ro) were between 1.20 and 1.90%. Thus, the mudstones are good shale gas source rocks. The thickness of the three mudstone sections was approximately 30–70 m, and the average porosity was 3.10%. The pore types were diverse with good reservoir capacity. The shale gas resources of the Carboniferous-Permian transitional facies estimated by the volumetric method were approximately 2798.97 × 108–4643.09 × 108 m3. Through a comparison with shales in SW China, where shale gas has been successfully exploited, we determined the preferred criteria for favorable shale gas areas, as well as favorable areas for shale gas enrichment.

Chapter 4 The Central Basin

1997 ◽  
Vol 17 (1) ◽  
pp. 47-74 ◽  
Author(s):  
W. Brian Harland ◽  
Simon R. A. Kelly ◽  
Isobel Geddes ◽  
Paul A. Doubleday
Keyword(s):  
Sedimentary Basins ◽  
Early Carboniferous ◽  
Source Rocks ◽  
Central Basin ◽  
Economic Interest ◽  
Early Permian ◽  
Coal Deposits ◽  
The Many ◽  
West Spitsbergen ◽  
Early Paleogene

Svalbard rocks conveniently divide into younger and older rocks at about the initial 'Carboniferous' boundary. There are, however, latest Devonian strata in places continuous with Carboniferous sedimentation. The older rocks are tectonically as well as stratigraphically complex. Beginning with the sub-Carboniferous (peneplane) unconformity resting variously on Devonian and pre-Devonian strata, it expressly excludes any older rocks.The term basin as in Central Basin applied here is used in a structural sense for what amounts to a broad brachysyncline. The accumulated strata were also formed in sedimentary basins with shifting depocentres. The most obvious is the Paleogene sedimentary and structural basin commonly referred to as the Tertiary Basin. The Central Basin excludes the western and southwestern areas (Chapters 9 and 10) where older and younger rocks are caught up in the Paleogene West Spitsbergen Orogeny. It also excludes the areas, mainly in the islands in the east, where subsidence was less marked at first and tectonic platform conditions prevailed. The younger succession, Tournaisian through Paleogene (a span of about 330 million years) has suffered only minor diastrophism in contrast to earlier events. Central Basin thus refers to the whole post Devonian cover or platform sequence in this study area.Most mineral prospects of economic interest in Svalbard belong to these younger rocks, from the many coal deposits of which Early Carboniferous and especially Early Paleogene horizons have been exploited. Furthermore, in the search for petroleum, source rocks of Late Carboniferous Early Permian, Early to Mid-Triassic and Jurassic age have been identified

Glacially influenced petroleum plays in the Kulshill Group (Late Carboniferous–Early Permian) of the Southeastern Bonaparte Basin, Western Australia

2008 ◽  
Vol 48 (1) ◽  
pp. 69 ◽  
Author(s):  
John Gorter ◽  
Sarah Poynter ◽  
Stewart Bayford ◽  
Andrea Caudullo
Keyword(s):  
Western Australia ◽  
Oil And Gas ◽  
Late Carboniferous ◽  
Early Permian ◽  
Glacial Ice ◽  
Sequence Stratigraphic ◽  
The North ◽  
Potential Reservoir ◽  
Reservoir Sandstones ◽  
The 1960S

Glacial deposits within the Lower Kulshill Group (Late Carboniferous-Early Permian) were initially recognised in cores from onshore wells in the southeastern Bonaparte Basin in the 1960s. Subsequent offshore wells have extended the distribution of the glaciogene units 100 km to the north. Their capacity to entrap oil and gas was proven by the Turtle and Barnett wells, located on the offshore Turtle High. Similar age glaciogene rocks occur within the Cooper Basin of central Australia, where they contain oil and gas reserves, and in the Canning, Carnarvon and Perth basins of Western Australia. Using sparse cores, electric logs, palynology and a sequence stratigraphic interpretation of 2D seismic data, the distribution of potential reservoir sandstones and sealing lithologies of the glaciogenic strata has been mapped for the offshore southeastern Bonaparte Basin. This study highlights the petroleum trapping potential associated with sub-glacial ice tunnel valley features, which are widespread in the offshore part of the basin.

Oil to Source Rock Correlation Using Biomarker Data Through Pattern Matching and Fingerprinting Analysis in “Kitkat” Field, Jabung Block, South Sumatra Basin

2020 ◽  
Author(s):  
S., R. Muthasyabiha
Keyword(s):  
Pattern Matching ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Maturity Level ◽  
Fingerprinting Analysis ◽  
Kerogen Type ◽  
Oil Characteristics ◽  
Biomarker Data

Geochemical analysis is necessary to enable the optimization of hydrocarbon exploration. In this research, it is used to determine the oil characteristics and the type of source rock candidates that produces hydrocarbon in the “KITKAT” Field and also to understand the quality, quantity and maturity of proven source rocks. The evaluation of source rock was obtained from Rock-Eval Pyrolysis (REP) to determine the hydrocarbon type and analysis of the value of Total Organic Carbon (TOC) was performed to know the quantity of its organic content. Analysis of Tmax value and Vitrinite Reflectance (Ro) was also performed to know the maturity level of the source rock samples. Then the oil characteristics such as the depositional environment of source rock candidate and where the oil sample develops were obtained from pattern matching and fingerprinting analysis of Biomarker data GC/GCMS. Moreover, these data are used to know the correlation of oil to source rock. The result of source rock evaluation shows that the Talangakar Formation (TAF) has all these parameters as a source rock. Organic material from Upper Talangakar Formation (UTAF) comes from kerogen type II/III that is capable of producing oil and gas (Espitalie, 1985) and Lower Talangakar Formation (LTAF) comes from kerogen type III that is capable of producing gas. All intervals of TAF have a quantity value from very good–excellent considerable from the amount of TOC > 1% (Peters and Cassa, 1994). Source rock maturity level (Ro > 0.6) in UTAF is mature–late mature and LTAF is late mature–over mature (Peters and Cassa, 1994). Source rock from UTAF has deposited in the transition environment, and source rock from LTAF has deposited in the terrestrial environment. The correlation of oil to source rock shows that oil sample is positively correlated with the UTAF.

Burial History Reconstruction of the Appalachian Basin in Kentucky, West Virginia, Pennsylvania, and New York, Using 1D Petroleum System Models

2019 ◽  
Vol 56 (4) ◽  
pp. 365-396
Author(s):  
Debra Higley ◽  
Catherine Enomoto
Keyword(s):  
New York ◽  
Vitrinite Reflectance ◽  
Structural Complexity ◽  
Appalachian Basin ◽  
Source Rocks ◽  
Burial History ◽  
Gas Generation ◽  
Deep Basin ◽  
Utica Shale ◽  
Wet Gas

Nine 1D burial history models were built across the Appalachian basin to reconstruct the burial, erosional, and thermal maturation histories of contained petroleum source rocks. Models were calibrated to measured downhole temperatures, and to vitrinite reflectance (% Ro) data for Devonian through Pennsylvanian source rocks. The highest levels of thermal maturity in petroleum source rocks are within and proximal to the Rome trough in the deep basin, which are also within the confluence of increased structural complexity and associated faulting, overpressured Devonian shales, and thick intervals of salt in the underlying Silurian Salina Group. Models incorporate minor erosion from 260 to 140 million years ago (Ma) that allows for extended burial and heating of underlying strata. Two modeled times of increased erosion, from 140 to 90 Ma and 23 to 5.3 Ma, are followed by lesser erosion from 5.3 Ma to Present. Absent strata are mainly Permian shales and sandstone; thickness of these removed layers increased from about 6200 ft (1890 m) west of the Rome trough to as much as 9650 ft (2940 m) within the trough. The onset of oil generation based on 0.6% Ro ranges from 387 to 306 Ma for the Utica Shale, and 359 to 282 Ma for Middle Devonian to basal Mississippian shales. The ~1.2% Ro onset of wet gas generation ranges from 360 to 281 Ma in the Utica Shale, and 298 to 150 Ma for Devonian to lowermost Mississippian shales.

Petroleum geological activities onshore West Greenland in 1996, and drilling of a deep exploration well

1997 ◽  
pp. 17-23 ◽  
Author(s):  
Flemming G. Christiansen ◽  
Anders Boesen ◽  
Finn Dalhoff ◽  
Asger K. Pedersen ◽  
Gunver K. Pedersen ◽  
...  
Keyword(s):  
Late Summer ◽  
Summer Season ◽  
Source Rocks ◽  
Press Releases ◽  
West Greenland ◽  
Potential Reservoir ◽  
Second Year ◽  
Deep Exploration ◽  
Exploration Well ◽  
Shed Light

NOTE: This article was published in a former series of GEUS Bulletin. Please use the original series name when citing this article, for example: Christiansen, F. G., Boesen, A., Dalhoff, F., Pedersen, A. K., Pedersen, G. K., Riisager, P., & Zinck-Jørgensen, K. (1997). Petroleum geological activities onshore West Greenland in 1996, and drilling of a deep exploration well. Geology of Greenland Survey Bulletin, 176, 17-23. https://doi.org/10.34194/ggub.v176.5055 _______________ The 1996 summer season saw continued petroleum geological activities in the Disko–Nuussuaq area, onshore West Greenland. These took the form of a geological field project led by the Geological Survey of Denmark and Greenland (GEUS), and continued commercial exploration by grønArctic Energy Inc. (grønArctic). In the second year of their licence, grønArctic carried out an airborne geophysical programme early in 1996 and drilled a c. 3 km deep exploration well on Nuussuaq, GRO#3, in the late summer (Fig. 1). Although the detailed results from grønArctic’s exploration are confidential (apart from the information made available at conferences and in press releases), it is evident that knowledge of the Nuussuaq Basin has greatly increased in recent years and that the basin has considerable exploration potential of its own (see Christiansen et al., 1995b, 1996a). The activities by GEUS and the exploration by grønArctic will significantly improve the understanding of the petroleum system of the basin; available data from the 1996 activities have shed light on the types and distribution of oils, source rocks and potential reservoir units.

Method of Early Prediction on Source Rocks in Basins with Low Exploration Activity

2007 ◽  
Vol 14 (4) ◽  
pp. 159-167 ◽  
Author(s):  
Zhen LIU ◽  
Mai CHANG ◽  
Yang ZHAO ◽  
Yunzhen LI ◽  
Huailei SHEN
Keyword(s):  
Source Rocks ◽  
Early Prediction ◽  
Exploration Activity

Evidence from the Changing Carbon Isotopic of Kerogen, Oil, and Gas during Hydrous Pyrolysis from Pinghu Formation, the Xihu Sag, East China Sea Basin

Energies ◽  
2021 ◽  
Vol 14 (24) ◽  
pp. 8317
Author(s):  
Qiang Cao ◽  
Jiaren Ye ◽  
Yongchao Lu ◽  
Yang Tian ◽  
Jinshui Liu ◽  
...  
Keyword(s):  
Carbon Isotopes ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Heating Time ◽  
Source Rocks ◽  
Evolution Process ◽  
Carbon Isotopic ◽  
Hydrous Pyrolysis ◽  
Increasing Temperature

Semi-open hydrous pyrolysis experiments on coal-measure source rocks in the Xihu Sag were conducted to investigate the carbon isotope evolution of kerogen, bitumen, generated expelled oil, and gases with increasing thermal maturity. Seven corresponding experiments were conducted at 335 °C, 360 °C, 400 °C, 455 °C, 480 °C, 525 °C, and 575 °C, while other experimental factors, such as the heating time and rate, lithostatic and hydrodynamic pressures, and columnar original samples were kept the same. The results show that the simulated temperatures were positive for the measured vitrinite reflectance (Ro), with a correlation coefficient (R2) of 0.9861. With increasing temperatures, lower maturity, maturity, higher maturity, and post-maturity stages occurred at simulated temperatures (Ts) of 335–360 °C, 360–400 °C, 400–480 °C, and 480–575 °C, respectively. The increasing gas hydrocarbons with increasing temperature reflected the higher gas potential. Moreover, the carbon isotopes of kerogen, bitumen, expelled oil, and gases were associated with increased temperatures; among gases, methane was the most sensitive to maturity. Ignoring the intermediate reaction process, the thermal evolution process can be summarized as kerogen0(original) + bitumen0(original)→kerogenr (residual kerogen) + expelled oil (generated) + bitumenn+r (generated + residual) + C2+(generated + residual) + CH4(generated). Among these, bitumen, expelled oil, and C2-5 acted as reactants and products, whereas kerogen and methane were the reactants and products, respectively. Furthermore, the order of the carbon isotopes during the thermal evolution process was identified as: δ13C1 < 13C2-5 < δ13Cexpelled oil < δ13Cbitumen < δ13Ckerogen. Thus, the reaction and production mechanisms of carbon isotopes can be obtained based on their changing degree and yields in kerogen, bitumen, expelled oil, and gases. Furthermore, combining the analysis of the geochemical characteristics of the Pinghu Formation coal–oil-type gas in actual strata with these pyrolysis experiments, it was identified that this area also had substantial development potential. Therefore, this study provides theoretical support and guidance for the formation mechanism and exploration of oil and gas based on changing carbon isotopes.

The Yenisei-Khatanga Composite Tectono-Sedimentary Element, Northern Siberia

2021 ◽  
pp. M57-2021-15
Author(s):  
E. V. Deev ◽  
G. G. Shemin ◽  
V. A. Vernikovsky ◽  
O. I. Bostrikov ◽  
P. A. Glazyrin ◽  
...  
Keyword(s):  
Siberian Craton ◽  
Middle Triassic ◽  
Foreland Basin ◽  
Early Carboniferous ◽  
Source Rocks ◽  
Total Thickness ◽  
Petroleum Potential ◽  
Early Paleocene ◽  
Middle Carboniferous ◽  
Severnaya Zemlya

AbstractThe Yenisei-Khatanga Composite Tectono-Sedimentary Element (YKh CTSE) is located between the Siberian Craton and the Taimyr-Severnaya Zemlya fold-and-thrust belt. The total thickness of the Mesoproterozoic-Cenozoic sediments of YKh CTSE reaches 20 to 25 km. They are divided into four tectono-sedimentary elements (TSE): (i) Mesoproterozoic-early Carboniferous Siberian Craton continental margin, (ii) middle Carboniferous-Middle Triassic syn-orogenic Taimyr foreland basin, (iii) late Permian-Early Triassic syn-rift, and (iv) Triassic-Early Paleocene post-rift. The last one is the most important in terms of its petroleum potential and is the most drilled part of the CTSE. Its thickness accounts for half of the total thickness of YKh CTSE. The margins of the post-rift TSE and the inner system of inversion swells and adjacent troughs and depressions were shaped by three tectonic events: (i) middle Carboniferous-Middle Triassic Taimyr orogeny, (ii) Late Jurassic-Early Cretaceous Verkhoyansk orogeny, (iii) Late Cenozoic uplift. These processes led to more intense migration of hydrocarbons, the trap formation and their infill with hydrocarbons. Triassic, Jurassic, and Lower Cretaceous source rocks are mostly gas-prone, and among 20 discovered fields in Jurassic and Cretaceous plays, 17 are gas or mixed-type fields.

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.

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