scholarly journals STRUCTURAL SETTING AND HYDROCARBON POTENTIAL OF KHARITE-NUQRA-KOMOMBO RIFT BASINS, SOUTH EGYPT: A PROSPECTIVE APPROACH

2021 ◽  
Vol 6 (3) ◽  
Author(s):  
Mostafa A ◽  
Sehim A ◽  
El Barkooky A ◽  
Hammed M
Keyword(s):  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Potential ◽  
Rift Basins ◽  
Tectonic Zone ◽  
Structural Setting ◽  
High Resolution Satellite Images ◽  
Potential Source Rock

— The sedimentary basins of Kharite, Nuqra, and Komombo are outlined with the potential geophysical data where the southern N-S Egyptian Nile course separates Nuqra and Kharit as the East Nile basins. Two commercial discoveries of Al Barka and West El Barka oil fields have been declared in the West Nile basin of Komombo. This work presents our insights on the structural setting and hydrocarbon system of these basins through our integrating results in form of interpreted seismic profiles and structural mapping on the different horizons, 1D basin modeling, geochemistry, and geologic maps based on high-resolution satellite images. Structurally, these rift basins are developed as NWtrending asymmetric fault-bounded half-grabens (oblique to the Red Sea trend) through the reactivation of a major Precambrian Pan African tectonic zone by the Neocomian extensional tectonics. The high potential source rock with up to 7wt. % TOC of kerogen II are proved in the Komombo basin. The seismic and drilling results show Neocomian-Barremian maximum subsidence and the possible occurrence of similar Neocomian source rocks in the eastern Nile basins. Additionally, the convenient clastic reservoir rocks occurred in the entire stratigraphic succession and seal capacity in the upper interval of Senonian-Paleocene. Good opportunities for hydrocarbon structural trapping take place in form of rotated fault blocks by the Early Cretaceous extensional rift and mildly inverted structures by a long span of Late Cretaceous to post-Early Eocene Syrian Arc compression in South Egypt. These elements were verified by Al Baraka discovery and present a promising play concept for hydrocarbon potential in the Kharit and Nuqra basins. The geochemical data indicate different basins exhumation and maturation levels, as the 0.5% calculated vitrinite reflectance "Ro" values occur at the depths of 1200ft and 2100ft in Nuqra and Komombo basins, respectively

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 Geochemical Evaluation of the Cretaceous Mudrocks and Sandstones (Wackes) in the Southern Bredasdorp Basin, Offshore South Africa: Implications for Hydrocarbon Potential

Minerals ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 595
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Nicola Wagner ◽  
Christopher Baiyegunhi
Keyword(s):  
South Africa ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Geochemical Data ◽  
Minor Amount ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
The Mean

The southern Bredasdorp Basin, off the south coast of South Africa, is only partly understood in terms of its hydrocarbon potential when compared to the central and northern parts of the basin. Hydrocarbon potential assessments in this part of the basin have been limited, perhaps because the few drilled exploration wells were unproductive for hydrocarbons, yielding trivial oil and gas. The partial integration of data in the southern Bredasdorp Basin provides another reason for the unsuccessful oil and gas exploration. In this study, selected Cretaceous mudrocks and sandstones (wacke) from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 drilled in the southern part of the Bredasdorp Basin were examined to assess their total organic carbon (TOC), thermal maturity, organic matter type and hydrocarbon generation potential. The organic geochemical results show that these rocks have TOC contents ranging from 0.14 to 7.03 wt.%. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S2/S3) values vary between 24–263 mg HC/g TOC, 4–78 mg CO2/g TOC, and 0.01–18 mgHC/mgCO2 TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20%, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the Bredasdorp source rocks have entered the oil window and are considered as effective source rocks in the Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. Based on the geochemical data, it can be inferred that most of the mudrocks and sandstones (wackes) in the southern part of the Bredasdorp Basin have attained sufficient burial depth and thermal maturity for oil and gas generation potential.

scholarly journals Studies on the onshore hydrocarbon potential in East Greenland 1986-87: field work from 72° to 74°N

1987 ◽  
Vol 135 ◽  
pp. 72-81
Author(s):  
C Marcussen ◽  
F.G Christiansen ◽  
P.-H Larsen ◽  
H Olsen ◽  
S Piasecki ◽  
...  
Keyword(s):  
Thermal History ◽  
Sedimentary Basins ◽  
Field Work ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
East Greenland ◽  
The North ◽  
Hydrocarbon Traps ◽  
Subsidence History ◽  
Tectonic Study

A study of the onshore hydrocarbon potential of central and northem East Greenland was initiated in 1986. Field work was carried out from early July to mid August covering the region between Kong Oscar Fjord and Kejser Franz Joseph Fjord (fig. 1). In 1987 field activities will continue further to the north, eventually reaching Danmarkshavn (77°N). The programme is a continuation of the 1982-83 investigations in Jameson Land (Surlyk, 1983; Surlyk et al., 1984a) and is part of a regional programme comprising petroleum geological studies of all sedimentary basins in Greenland (Larsen & Marcussen, 1985; Larsen, 1986). The aim of the two-year field study followed by laboratory analyses is: (1) to study the presence and distribution of potential hydrocarbon source rocks in the region; (2) to evaluate the thermal history and maturity pattern of the region including the thermal effect of Tertiary intrusions and volcanics; (3) to make a stratigraphic, sedimentological and tectonic study of the region with special emphasis on subsidence history, reservoir formation and potential hydrocarbon traps.

COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 117 ◽  
Author(s):  
C.J. Boreham ◽  
J.E. Blevin ◽  
A.P. Radlinski ◽  
K.R. Trigg
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Middle Eocene ◽  
Vitrinite Reflectance ◽  
Mineral Resources ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Australian Context ◽  
Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

Hydrocarbon potential and prospects for exploration of Eastern Arctic oil and gas deposits

2021 ◽  
pp. 85-92
Author(s):  
V. Yu. Kerimov ◽  
◽  
E. A. Lavrenova ◽  
R. N. Mustaev ◽  
Yu. V. Shcherbina ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Sedimentary Basins ◽  
Space Time ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Basin Modeling ◽  
Single Model ◽  
Gas Reservoirs ◽  
Oil Hydrocarbons ◽  
Potential Traps

Conditions for the formation of hydrocarbon systems and prospects for searching for accumulations of oil and gas in the waters of the Eastern Arctic are considered. Significant hydrocarbon potential is predicted in the sedimentary basins of this region. All known manifestations of oil hydrocarbons are installed on land adjacent to the south, as well as on the east of the shelf. The East Arctic waters are included in a single model in order to perform an adequate comparative analysis of the evolution of hydrocarbon systems. The purpose of the research was to build space-time digital models of sedimentary basins and hydrocarbon systems, and to quantify the volume of generation, migration, and accumulation of hydrocarbons for the main horizons of source rocks. To achieve this goal, a spatiotemporal numerical basin simulation was carried out, based on which the distribution of probable hydrocarbon systems was determined and further analyzed. Following to the data obtained the most probable HC accumulation zones and types of fluids contained in potential traps were predicted. Keywords: numerical space-time basin modeling; modeling of hydrocarbon systems; evidence of oil and gas presence; Eastern Arctic; elements of hydrocarbon systems; oil and gas reservoirs; migration; accumulation; perspective objects

Identification of uraniferous granitoids in the USA using stream sediment geochemical data

1981 ◽  
Vol 44 (336) ◽  
pp. 455-470 ◽  
Author(s):  
R. J. Howarth ◽  
G. S. Koch ◽  
J. A. Plant ◽  
R. K. Lowry
Keyword(s):  
Trace Element ◽  
Sedimentary Basins ◽  
Stream Sediments ◽  
Uranium Mineralization ◽  
Stream Sediment ◽  
Source Rocks ◽  
Sediment Geochemistry ◽  
Geochemical Data ◽  
Front Range ◽  
The Usa

AbstractTrace element variations in stream sediments from an area of 76 000 km2 in central Colorado are used to identify uraniferous granitoids on the basis of whole rock geochemical criteria developed to distinguish barren from metalliferous granitoids in Britain. These criteria (which include enhanced Ba, Be, Cs, Cs/Ba, K, La/Eu, Li, Lu/Eu, Nb, Rb, Rb/K, low Sr and Mg, and RE patterns with marked negative Eu anomalies) are used to formulate an index based on the Pikes Peak batholith of the Front Range as a type uranium source rock.Uraniferous granitoids in Colorado, which are associated with sedimentary basins containing major uranium mineralization, are identified using this index which may be applicable to the interpretation of stream sediments from elsewhere. The use of stream sediment geochemistry as an exploration method for similar uranium source rocks, which may indicate potential uranium provinces, is thus possible.

Constraining Late Cretaceous exhumation in the Eromanga Basin using sonic velocity data

2016 ◽  
Vol 56 (1) ◽  
pp. 101
Author(s):  
Mitchell Keany ◽  
Simon Holford ◽  
Mark Bunch
Keyword(s):  
Late Cretaceous ◽  
Vitrinite Reflectance ◽  
Sedimentary Basins ◽  
Analysis Data ◽  
Source Rocks ◽  
Fine Grained ◽  
Seal Integrity ◽  
Central Australia ◽  
Petroleum Wells ◽  
Eromanga Basin

Exhumation in sedimentary basins can have significant consequences for their petroleum systems. For example, source rocks may be more mature than their present-day burial depths suggest, increased compaction can result in reduced reservoir quality, and seal integrity problems are commonly encountered. The Eromanga Basin in central Australia experienced an important phase of exhumation during the Late Cretaceous, though the magnitude and spatial distribution of exhumation is poorly constrained. In this study exhumation magnitudes have been determined for 100 petroleum wells based on sonic transit time analyses of fine grained shales, siltstones and mudstones within selected Cretaceous stratigraphic units. Observed sonic transit times are compared to normal compaction trends (NCTs) determined for suitable stratigraphic units. The Winton Formation and the Bulldog Shale/Wallumbilla Formation were chosen for analysis in this study for their homogenous, fine-grained and laterally extensive properties. Exhumation magnitudes for these stratigraphic units are statistically similar. Results show net exhumation in the southern Cooper-Eromanga Basin (<500 m [~1,640 ft]) and higher net exhumation magnitudes (up to 1,400 m [~3,937 ft]) being recorded in the northeastern margins of the basin. Gross exhumation magnitudes show significant variation across short distances suggesting different tectonic processes acting upon the basin. Independent vitrinite reflectance and apatite fission track analysis data, available for a subset of wells, give statistically similar exhumation magnitudes to those that have been calculated through the compaction methodology, giving confidence in these results. The effect on source rock generation is illustrated through 1D basin modelling where exhumation is shown to impact the timing and type of the hydrocarbons generated. The improved quantification of this exhumation permits a better understanding of the Late Cretaceous tectonics and palaeogeography of central Australia.

Overpressure release: Fluid inclusion evidence for a new mechanism for the formation of heavy oil

Geology ◽  
2020 ◽  
Vol 48 (8) ◽  
pp. 803-807
Author(s):  
Hongwei Ping ◽  
Chunquan Li ◽  
Honghan Chen ◽  
Simon C. George ◽  
Se Gong
Keyword(s):  
Heavy Oil ◽  
Sedimentary Basins ◽  
Polar Compounds ◽  
Source Rocks ◽  
Geochemical Data ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Heavy Oils ◽  
Dongpu Depression ◽  
Hydrocarbon Distribution

Abstract Heavy oils in sedimentary basins are commonly related to biodegradation and water washing, and thermal degradation of sulfur-rich kerogen at an early hydrocarbon generation stage. However, the potential for overpressure release to form heavy oil has been seldom considered and rarely demonstrated. Paragenetic sequences of diagenetic and oil charge events, pressure-temperature-composition (P-T-x) evolutionary history reconstruction, and molecular geochemical data from a single generation of oil inclusions reveal that heavy shale oil in the PS18–1 well in the Dongpu Depression, Bohai Bay Basin, China, was neither a product of biodegradation nor due to early oil generation during kerogen maturation. Instead, the precipitation and retention of polar compounds of a previously charged, higher-maturity oil from deeper source rocks, induced by intense pressure reduction during basin uplift, represent the most likely mechanism for the formation of the heavy oil. The precipitation of polar compounds during primary and secondary migration due to intense pressure release may be an important mechanism for explaining compositional fractionation effects in the expelled petroleum fluids in source rocks, bitumen, and heavy oil distributions in unconventional shale systems, and deep non-biodegraded heavy oils. This mechanism has wider implications for understanding the hydrocarbon distribution in overpressured basins.

scholarly journals Hydrocarbon source rock evaluation of the Lower Cretaceous system in the Baibei Depression, Erlian Basin

2017 ◽  
Vol 36 (3) ◽  
pp. 355-372 ◽  
Author(s):  
Hua Liu ◽  
Jinglun Ren ◽  
Jianfei Lyu ◽  
Xueying Lyu ◽  
Yuelin Feng
Keyword(s):  
Organic Carbon ◽  
Total Organic Carbon ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Main Stage ◽  
Type I ◽  
Potential Source Rock ◽  
Erlian Basin

The K1s, K1d, K1t, and K1a Formations are potential source rock intervals for hydrocarbon formation, all of which are part of the Lower Cretaceous system in the Baibei Depression in the Erlian Basin in China. However, no well has found oil flow because the hydrocarbon-generating potential of the source rocks has not been comprehensively evaluated. Based on organic geochemical and petrological analyses, all the source rocks possess highly variable total organic carbon and S1 + S2 contents. Total organic carbon and S1 + S2 contents indicate that the K1a2 Formation through the K1d1 Formation are source rocks that have fair to good generative potential and the K1d2 Formation through the K1s Formation are source rocks that have good to very good generative potential. The organic matter in the K1a2 Formation is dominated by Type I and II kerogen; thus, it is considered to be oil prone based on H/C versus O/C plots. Most of the analyzed samples were deposited in reducing environments and sourced from marine algae; thus, they are oil prone. However, only two source rock intervals were thermally mature with vitrinite reflectance values in the required range. Hydrocarbon-generating histories show that the K1t and K1a2 intervals began to generate hydrocarbons during the depositional period of the K1d2 and K1d3 Formations, respectively, and stopped generating hydrocarbons at the end of the depositional period of the late Cretaceous. Therefore, the main stage of hydrocarbon migration and accumulation was between the depositional period of the K1d2 and K1s Formations, and the critical moment was the depositional period of the late K1s Formation. The generation conversion efficiency reached approximately 55% in the K1a2 Formation and 18% in the K1t Formation at the end of the Cretaceous sedimentary stage. In general, the effective oil traps are those reservoirs that are near the active source rock in the generating sags in the Baibei Depression.

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