scholarly journals Use of Geochemical Fossils as Indicators of Thermal Maturation: An Example from the Anambra Basin, Southeastern Nigeria

2015 ◽  
Vol 2015 ◽  
pp. 1-11 ◽  
Author(s):  
Olumuyiwa Adedotun Odundun
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Land Plant ◽  
Source Rocks ◽  
Chemical Compositions ◽  
Organic Input ◽  
Southeastern Nigeria ◽  
Anambra Basin ◽  
Subsurface Sediments ◽  
Geochemical Studies

Organic geochemical studies and fossil molecules distribution results have been employed in characterizing subsurface sediments from some sections of Anambra Basin, southeastern Nigeria. The total organic carbon (TOC) and soluble organic matter (SOM) are in the range of 1.61 to 69.51 wt% and 250.1 to 4095.2 ppm, respectively, implying that the source rocks are moderately to fairly rich in organic matter. Based on data of the paper, the organic matter is interpreted as Type III (gas prone) with little oil. The geochemical fossils and chemical compositions suggest immature to marginally mature status for the sediments, with methyl phenanthrene index (MPI-1) and methyl dibenzothiopene ratio (MDR) showing ranges of 0.14–0.76 and 0.99–4.21, respectively. The abundance of 1,2,5-TMN (Trimethyl naphthalene) in the sediments suggests a significant land plant contribution to the organic matter. The pristane/phytane ratio values of 7.2–8.9 also point to terrestrial organic input under oxic conditions. However, the presence of C27 to C29 steranes and diasteranes indicates mixed sources—marine and terrigenous—with prospects to generate both oil and gas.

scholarly journals Geochemical and hydrogeological parameters informativity in oil and gas geology

Georesursy ◽  
2021 ◽  
Vol 23 (2) ◽  
pp. 214-220
Author(s):  
Maria A. Bolshakova ◽  
Anna V. Korzun ◽  
Antonina V. Stoupakova ◽  
Roman S. Sautkin ◽  
Anton G. Kalmykov ◽  
...  
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Fluid Dynamic ◽  
Development Stage ◽  
Source Rocks ◽  
Salt Deposition ◽  
Hydrogeological Parameters ◽  
Stage Of Development ◽  
Geochemical Studies ◽  
Dynamic Connectivity

The article discusses the fundamental possibilities of using the results of geochemical and hydrogeochemical studies of organic matter, oils and waters in oil and gas geology, including for objects at the stage of development. It is shown that complex geochemical studies of oils and waters make it possible to get more correct conclusions about the presence or absence of fluid-dynamic connectivity of different horizons. Studies of organic matter and oils allow (by basin modeling instrument) to understand the contribution of different source rocks to formation of oils of different reservoirs. Hydrogeochemical studies of associated waters and waters used in the reservoir pressure maintenance system in a complex of works not only actively complements the knowledge about the presence or absence of fluid-dynamic connections between reservoirs and production objects, but also make it possible to predict, for example, salt deposition on equipment and in the reservoirs, and therefore allow you to prevent the possibility of unwanted salt deposition. The conclusions are based on the results of comprehensive geological and geochemical studies carried out by the authors for one of the deposits of the Krasnoleninsky arch of Western Siberia, which is at the development stage, as well as on the previous experience of the authors.

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 HABITAT OF THE SURAT/BOWEN BASIN

1982 ◽  
Vol 22 (1) ◽  
pp. 213 ◽  
Author(s):  
B. M. Thomas ◽  
D. G. Osborne ◽  
A. J. Wright
Keyword(s):  
Oil And Gas ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Lateral Migration ◽  
Early Maturity ◽  
Oil And Gas Fields ◽  
Basement Rocks ◽  
Origin Of Oil ◽  
Gas Fields ◽  
Geochemical Studies

Ever since the early discoveries at Cabawin (1960) and Moonie (1961), the origin of oil and gas in the Surat/Bowen Basin has been a subject of speculation. Hydrocarbons have been found in reservoirs ranging in age from Permian to Early Jurassic; even fractured pre-Permian 'basement' rocks have occasionally recorded shows.Recent geochemical studies have identified rich source rocks within the Jurassic, Triassic and Permian sequences. The Middle Jurassic Walloon Coal Measures are thermally immature throughout the Surat Basin and are unlikely to have generated significant amounts of hydrocarbons. Lower Jurassic Evergreen Formation source rocks have reached 'nominal early maturity' (VR = 0.6) in parts of the basin. The Middle Triassic Moolayember Formation lies within the oil generation zone in the northern Taroom Trough. However, no oil has yet been confidently correlated with either a Jurassic or a Triassic source. On geochemical and geological grounds it is likely that most, if not all, of the hydrocarbons discovered to date were generated from Permian source rocks.The probability of finding gas as well as oil in Permian, Triassic or Jurassic reservoirs increases from south to north, in accord with organic maturity trends in the Permian of the Taroom Trough. On the narrow thrust-bounded eastern flank, vertical migration has occurred, resulting in oilfields at Moonie and Bennett. In contrast, extensive lateral migration of hydrocarbons across the gentle western flank of the basin is indicated by numerous small oil and gas fields on the Roma Shelf and Wunger Ridge.

PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS

1994 ◽  
Vol 34 (1) ◽  
pp. 279 ◽  
Author(s):  
Dennis Taylor ◽  
Aleksai E. Kontorovich ◽  
Andrei I. Larichev ◽  
Miryam Glikson
Keyword(s):  
Organic Matter ◽  
Chemical Evolution ◽  
Oil And Gas ◽  
Source Rocks ◽  
Type I ◽  
Peak Oil ◽  
Gas Generation ◽  
Oil Generation ◽  
Physical And Chemical ◽  
Extractable Organic Matter

Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.

Geochemical Characteristics of the Campano-Maastrictian Sediments of the Anambra Basin, Southeastern Nigeria - Implication For Provenance, Paleodepositional Environment, Maturity and Tectonic Setting

2021 ◽  
Author(s):  
Michael Edirin Okiotor ◽  
EDeh Desiree Ogueh
Keyword(s):  
Inductively Coupled Plasma ◽  
Tectonic Setting ◽  
Passive Margin ◽  
Source Rocks ◽  
Sediment Provenance ◽  
Southeastern Nigeria ◽  
Inductively Coupled ◽  
Anambra Basin ◽  
Plasma Mass Spectrometry ◽  
Chemical Index Of Alteration

Abstract The present study investigates the Anambra Basin shales to determine the provenance and maturity of the sediments using standard geochemical techniques. Twelve (12) representative samples recovered from shale sequences of The Mamu Formation and Nkporo Group of The Anambra Basin were studied to determine the sediment provenance, paleoenvironment, diagenetic conditions, maturity as well as the tectonic setting. To consider in detail and establish the inherent constituents of the Major minerals, Trace and Rare Earth elements, Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses techniques was employed. The detrital minerals determined are Al2O3 (18.27% and 21.16%), TiO2 (1.73% and 1.63%) and Fe2O3 (2.78% \ and 2.85%), for Nkporo Group and Mamu Formation respectively. The enrichment of SiO2, Al2O3 and TiO2 (1.14, 1.94, 3.67 respectively) supported by Chemical Index of Alteration (CIA) of 93.54 & 39.55 and Rb/Sr ratio of 0.57 & 0.40, indicate that the Anambra Basin sediments are matured. TiO2/AL2O3 binary plots, Th/Co Vs La/Sc crossplots, Th-Sc-Zr triplots and Cr, Ni concentration suggest mixed provenance of felsic to mafic source rocks for these sediments. From the log (K2O/Na2O) Vs SiO2 crossplots, a passive margin tectonic setting was determined for these sediments.

Jurassic source rocks of hydrocarbon fluids in the Eastern part of the Fukan depression (Junggar oil and gas basin)

2020 ◽  
pp. 55-63
Author(s):  
Yang Houqiang ◽  
E. V. Soboleva
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Research Area ◽  
Molecular Composition ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Eastern Side ◽  
Oil And Gas Reservoirs

In recent years, significant successes have been achieved in the search and exploration of oil and gas reservoirs in the Jurassic deposits on the eastern side of the Fukang depression, which is the least studied part of the Junggar oil and gas Basin. In order to find out the source of hydrocarbon generation, we studied source rocks, oil and oil-bearing sandstones (24 samples from 13 wells) from the Badaowan, Sangonghe, Xishanyao, Toutunhe and Qigu production beds of the Fukang depression research area. Based on these studies, the composition of the organic matter of the Jurassic source rocks, the properties and molecular composition of oils, as well as the characteristics of the composition of biomarkers in them are examined in detail. The results of research and interpretation of the data showed that the mudstones of the Badaowan formation were source rocks of oil from the Gumudi zone, the Fukan depression, the Bajiahai ledge and the Shaqi ledge.

scholarly journals Geochemical conditions of oil and gas potential of the South Caspian basin on the basis of pyrolytic studies of mud volcanoes

2019 ◽  
Vol 98 ◽  
pp. 02007
Author(s):  
Rustam Mustaev ◽  
Javidan Ismailov ◽  
Uliana Serikova
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Caspian Basin ◽  
Thermal Maturity ◽  
Mud Volcanoes ◽  
The South ◽  
South Caspian Basin ◽  
Geochemical Conditions ◽  
Geochemical Studies ◽  
Gas Potential

This paper provides the results of geochemical studies with products of mud volcanoes conducted for a purpose of evaluating the generative potential of the South-Caspian basin. The kerogen types have been identified for different stratigraphic intervals and stages of the organic matter (OM) thermal maturity have been determined. A correlation has been established between the generative potential and the basin deposition and subsidence rate.

scholarly journals Comparative Assessment of Hydrocarbon Generation Potential of Organic Matter from Shale Sediments along Isugwuato – Okigwe Axis, Anambra Basin, SE Nigeria

2021 ◽  
Vol 25 (3) ◽  
pp. 353-362
Author(s):  
M.U. Uzoegbu ◽  
C.U. Ugwueze
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Oxygen Index ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Generation Potential ◽  
Anambra Basin ◽  
Kerogen Type ◽  
Oil Generation ◽  
Carbonaceous Shales ◽  
Petroleum Generation

TRACT: The Cretaceous sediments in the Anambra Basin (SE Nigeria) consist of a cyclic succession of coals, carbonaceous shales, silty shales and siltstones  interpreted as deltaic deposits. The objective of this study is to compare the hydrocarbon generation potential of organic matter from shale sediments along Isugwuato-Okigwe axis in the Anambra Basin, Nigeria. Data obtained indicates the presence of Type III kerogen with Tmax values are between 424 and 441ºC indicating that the shales are thermally immature to marginally mature with respect to petroleum generation. Hydrogen Index (HI) values range from 14 to 388.9mgHC/gTOC while S1 + S2 yields values ranging from 0.2 to 1.0mgHC/g rock, suggesting that the shale have gas generating potential. The TOC values rangesfrom 1.3 to 3.0%, an indication of a good source rock of terrestrially derived organic matter. The high oxygen index (OI) (16.3 mgCO2g-1TOC), TS (1.35) and TOC/TS (1.5) suggest deposition in a shallow marine environment. Based on the kerogen type, shales from the studied area will equally generate oil and gas if its organic matter attained sufficient thermal temperature. Keywords: Shale, kerogen type, maturity, oil generation.

scholarly journals Depositional Environments and Geochemical Assessments of the Bende Ameki Formation Potential as Petroleum Source Rocks in the Ogbunike Quarry, South-Eastern Nigeria

2018 ◽  
Vol 14 (27) ◽  
pp. 157 ◽  
Author(s):  
Olajubaje T. A. ◽  
Akande S.O. ◽  
Adeoye J. A. ◽  
Adekeye O. A. ◽  
Friedrich C.
Keyword(s):  
Niger Delta ◽  
Oil And Gas ◽  
Depositional Environments ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Rare Type ◽  
Southeastern Nigeria ◽  
Genetic Potential ◽  
Oxygenated Water

This paper focuses on investigating the paleoenvironments and hydrocarbon generation potentials of the outcropping Eocene Bende-Ameki Formation at Ogbunike quarry, Anambra Basin southeastern Nigeria, which is the Niger Delta Agbada Formation subsurface equivalent. The fine to coarse sandstones interbedded with parallel laminated grey, coaly shales, and bioturbated claystones were the dominant rock facies. The shales contain Ammobaculities, Ammontium, lenticulina, and Reophax benthic foraminifera of brackish to outer shelf environments. The rock sequence and biofacies associations indicate a fluvial, shoreface to delta environments. The marine and continental paleoenvironments are supported by the concentration and association of redox-sensitive trace elements such as vanadium and nickel of oxic to dysoxic paleoconditions. The twenty shales have a range of TOC from 0.39 - 8.81 wt% (mean 2.2 2 wt%), suggesting a good to very good source rocks. The organic richness is highest within the depth of 2 – 6 m across the quarry. Their genetic potential (S1+S2) ranges from 0.22 - 27.35 (mean 2.8 kgHC/ton) of rock, and hydrogen index from 26 to 292 mgHC/gTOC with a mean of 67.3 mgHC/gTOC. This, however, indicates dominance of Type III gas prone kerogen of terrestrial origin. The oxygenated water column characterized by the presence of benthonic scavengers may not preserve lipidenriched organic constituents of anoxic paleoenvironments which could account for the rare Type II oil and gas prone kerogen in the source rock. The thermal history inferred from the Tmax between 401°C - 424°C suggests that the source rocks are immature at the present stratigraphic level.

scholarly journals Permian petroleum system of Lena-Anabar trough - lithological-geochemical studies (at an example of well Ust’-olenek 2370)

2016 ◽  
pp. 71-81
Author(s):  
E. A. Bakay ◽  
M. E. Smirnova ◽  
N. I. Korobova ◽  
D. V. Nadezhkin
Keyword(s):  
Organic Matter ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Marine Organic Matter ◽  
Geochemical Study ◽  
Study Results ◽  
Core Descriptions ◽  
Geochemical Studies ◽  
First Time ◽  
Sand Bodies

Lithofacies of different genesis were determined within the Permian sequence, basing on analysis of core descriptions. The best reservoirs are associated with deltaic sand bodies. Permian source rocks with marine organic matter were distinguished. Initial organic matter parameters were estimated, initial good-excellent petroleum potential was suggested. Lithological-geochemical study results for core samples from one of the northern wells of Laptev Sea coast are published for the first time.

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