scholarly journals Optical (visual) Kerogen assessment of Enugu Shale, Anambra Basin, Southeastern Nigeria: Implications for source rock potential and thermal maturation

2021 ◽  
Vol 19 (1) ◽  
pp. 123-132
Author(s):  
Osita Igwebuike Chiaghanam ◽  
Okechukwu Nicodemus Ikegwuonu ◽  
Chikodi Jennifer Ekwegbalu ◽  
Emmanuel Ude Aniwetalu ◽  
Kingsley Chukwuebuka Chiadikobi
Keyword(s):  
Source Rock ◽  
Sedimentary Basins ◽  
Geochemical Data ◽  
Carbonaceous Shale ◽  
Thermal Alteration ◽  
Southeastern Nigeria ◽  
Petroleum Potential ◽  
Anambra Basin ◽  
Kerogen Type ◽  
Rock Eval

Palynological analysis was carried out on Ten (10) samples from outcrops of the Campanian Enugu Formation, a component  lithostratigraphic unit of the Anambra Basin, using the acid maceration techniques for recovering acidinsoluble organic-walled microfossils. Two main lithological units were encountered, which include: carbonaceous shale and siltstone. Result from kerogen  laboratory examination reveals two (2) main groups of palynofacies association namely; palynofacies (A and B), based on the change in particulate organic matter constituents of organic residue extract. Palynofacies A is characterized by abundant opaques debris with common terrestrial phytoclasts, which occupy the southwestern and northwestern parts of the studied area, whereas palynofacies B  dominates in the northeastern part, characterised by abundant phytoclasts followed by frequent opaques debris. Kerogen type III with gas-prone material is suggested for both palynofacies. The examined exine of spore/ pollen grain are pale yellow – yellow, with Thermal Alteration Index TAI of 1+ to 2- and Vitrinite Reflectane (R o) (0.3 % - 0.4 %) in palynofacies A, and yellow – yellow brown, with Thermal Alteration Index TAI of 2- to 2, and Vitrinite Reflectane (R o) of 0.3% - 0.5% in palynofacies B. These revealed source rock that is thermally immature to slightly mature but has potential to generate mainly gas. The kerogen data generated using transmitted light microscopy correlated well with geochemical data obtained using rock-eval pyrolysis method, and this shows the method a reliable tool for assessing  petroleum potential in any given sedimentary basins.

scholarly journals Geochemical characteristics and depositional environments of the Narimba Formation source rock, Bass Basin, Australia

2020 ◽  
Vol 10 (8) ◽  
pp. 3207-3225
Author(s):  
Mohamed Ragab Shalaby ◽  
Muhammad Izzat Izzuddin bin Haji Irwan ◽  
Liyana Nadiah Osli ◽  
Md Aminul Islam
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Depositional Environments ◽  
Geochemical Characteristics ◽  
Type Ii ◽  
Wet Gas ◽  
Kerogen Type ◽  
Rock Characterization ◽  
Rock Eval ◽  
Oil Gas

Abstract This research aims to conduct source rock characterization on the Narimba Formation in the Bass Basin, Australia, which is made of mostly sandstone, shale and coal. The geochemical characteristics and depositional environments have been investigated through a variety of data such as rock–eval pyrolysis, TOC, organic petrography and biomarkers. Total organic carbon (TOC) values indicated good to excellent organic richness with values ranging from 1.1 to 79.2%. Kerogen typing of the examined samples from the Narimba Formation indicates that the formation contains organic matter capable of generating kerogen Type-III, Type-II-III and Type-II which is gas prone, oil–gas prone and oil prone, respectively. Pyrolysis maturity parameters (Tmax, PI), in combination with vitrinite reflectance and some biomarkers, all confirm that all samples are at early mature to mature and are in the oil and wet gas windows. The biomarkers data (the isoprenoids (Pr/Ph), CPI, isoprenoids/n-alkanes distribution (Pr/nC17 and Ph/nC18), in addition to the regular sterane biomarkers (C27, C28 and C29) are mainly used to evaluate the paleodepositional environment, maturity and biodegradation. It has been interpreted that the Narimba Formation was found to be deposited in non-marine (oxygen-rich) depositional environment with a dominance of terrestrial plant sources. All the analyzed samples show clear indication to be considered at the early mature to mature oil window with some indication of biodegradation.

scholarly journals Geochemical Characterization and Thermal Maturation of Cerrejón Formation: Implications for the Petroleum System in the Ranchería Sub-Basin, Colombia

Geosciences ◽  
2020 ◽  
Vol 10 (7) ◽  
pp. 258
Author(s):  
Luis Felipe Cruz-Ceballos ◽  
Mario García-González ◽  
Luis Enrique Cruz-Guevara ◽  
Gladys Marcela Avendaño-Sánchez
Keyword(s):  
Source Rock ◽  
Vitrinite Reflectance ◽  
Central Area ◽  
Petroleum System ◽  
Geochemical Data ◽  
Burial History ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Rock Eval ◽  
Upper Paleocene

The Upper Paleocene Cerrejón Formation is a great source of coal in Colombia. The northeastern part of the Ranchería Sub-Basin sees the most intense mining activity. As a consequence, all geological studies have been concentrated on this region. Consequently, neither the distribution of the Cerrejón Formation, nor the quality and quantity of organic matter in the rest of the sub-basin is clear. In this study, we analyzed new geochemical data from Rock–Eval pyrolysis analyses and vitrinite reflectance using core samples from the ANH-CAÑABOBA-1 and ANH-CARRETALITO-1 wells. Based on this information, it was possible to classify the geochemical characteristics of the Cerrejón Formation as a source rock, particularly in the central area of the sub-basin, which had not been extensively studied before. Additionally, based on the interpretation of seismic reflection data, the numerical burial history models were reconstructed using PetroMod software, in order to understand the evolution of the petroleum system in the sub-basin. The models were calibrated with the data of maximum pyrolysis temperature (Tmax), vitrinite reflectance (%Ro), and bottom hole temperature (BHT). We infer the potential times of the generation and expulsion of hydrocarbon from the source rock.

scholarly journals Source Rock Evaluation of the Upper Triassic Baluti Formation in Bekhme-1 and Gulak-1 Wells from Akri-Bijeel Block, Kurdistan-Iraq

2021 ◽  
Vol 5 (1) ◽  
pp. 50-59
Author(s):  
Ayad N. F. Edilbi ◽  
Kamal Kolo ◽  
Blind F. Khalid ◽  
Mardin N. Muhammad Salim ◽  
Sana A. Hamad ◽  
...  
Keyword(s):  
Source Rock ◽  
Upper Triassic ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Petroleum Potential ◽  
Fold And Thrust Belt ◽  
Potential Source Rock ◽  
Source Rock Evaluation ◽  
Area North ◽  
Rock Eval

This study reports on the petroleum potential of the Upper Triassic Baluti Formation in Bekhme-1 and Gulak-1 Wells from Akri¬-Bijeel Block within the Bekhme Anticline area, North of Erbil City. The area is a part of the Zagros Fold and Thrust Belt, and is locally situated within the High Folded Zone. Typically, the Baluti Formation is composed of gray and green shale calcareous dolomite with intercalations of thinly bedded dolomites, dolomitic limestones, and silicified limestones which in places are brecciated. The geochemical indicators obtained from Rock-Eval pyrolysis of Baluti samples gave Total Organic Carbon content (TOC wt. %) average values of 0.15 and 0.18 wt. % and potential hydrocarbon content (S2) average values of 0.78 mg HC/g rock and 0.58 mg HC/g rock for Bekhme-1 and Gulak-1 respectively, suggesting a source rock of poor potential. The type of organic matter is of mixed type II-III and III kerogens with an average Tmax value of 440 °C for both boreholes, exhibiting early to peak stage of thermal maturity. Considering the results of this study, it is concluded that Baluti Formation in the studied area can not be regarded as a potential source rock for hydrocarbon generation.

scholarly journals Organic Geochemical Analysis of Shaly Facies from Two Wells Within Anambra Basin, Southeastern Nigeria

2018 ◽  
Vol 64 (4) ◽  
pp. 1-10
Author(s):  
P.R Ikhane ◽  
O.V Oladipo ◽  
O.A Adeagbo ◽  
O.O Oyebolu
Keyword(s):  
Organic Matter ◽  
Maximum Temperature ◽  
Geochemical Analysis ◽  
Southeastern Nigeria ◽  
Type Iii ◽  
Type Iv ◽  
Genetic Potential ◽  
Anambra Basin ◽  
Geochemical Parameters ◽  
Kerogen Type

Abstract Organic geochemical analysis of two selected wells penetrating shale facies of the Anambra basin was conducted with the view of evaluating the section in terms of quantity and quality of organic matter, genetic potential, organic matter type, thermal maturity as well as determining the type of hydrocarbon that could be generated. Geochemical parameters such as Total Organic Carbon (TOC), S1 (representing free and adsorbed hydrocarbons present), S2 (representing hydrocarbons generated directly from the kerogen), S3 (carbon dioxide CO2 present) and maximum temperature (Tmax) as well as Hydrogen Index (HI), Oxygen Index (OI), Production Index (PI) and Genetic Potential (GP) were derived and calculated from the pyrolysis data. Result indicated that Well 1 samples have an average TOC of 1.21 wt % which is considered good in organic matter quantity and fair in quality, while Well 2 samples are organically lean, poor in quantity and quality with average TOC value of 0.15 wt %. The Genetic Potential (GP) expressed as (S1+S2) for Well 1 and Well 2 averages 2.03 and 0.68 mg HC/g respectively, indicating, a poor generational potential. The HI, OI and S2/S3 values of Well 1 samples are 146.56 mg HC/g, 226.78 mg HC/g and 0.86 respectively which on plots suggest the kerogen as type IV although few samples fall within the type III area. This contrasts with Well 2 samples having HI, OI and S2/S3 values as 343.67 mg HC/g, 276.78 mg HC/g and 1.26 respectively. Thus making the kerogen type to be interpreted as type III. Judging from Tmax (average of 441.67°C for Well 1 and 470.44°C for Well 2) and PI (average of 0.13 for Well 1 and 0.24 for Well 2) values, Well 1 samples are within the oil generating window whereas Well 2 samples are overmatured generating dry gas. Deductions from the result of geochemical analysis show that the kerogen of Well 1 samples will generate oil while that of Well 2 samples have propensity to generate dry gas.

scholarly journals Hydrocarbon Potential of the Late Permian and the Late Triassic Source Rocks from the Qamdo (Changdu) Basin, Eastern Tibet and Its Linkage with the Sea Level Change

2021 ◽  
Vol 9 ◽  
Author(s):  
Zhaolin Qi ◽  
Yalin Li ◽  
Chengshan Wang
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Upper Triassic ◽  
Source Rocks ◽  
Late Triassic ◽  
Upper Permian ◽  
Late Permian ◽  
Petroleum Potential ◽  
Eastern Tibet ◽  
Rock Eval

The Qamdo Basin in eastern Tibet has significant petroleum potential and previous studies indicate that the basin contains thick potential source rocks of the Late Permian and the Late Triassic ages. In this paper, the petroleum potential of samples from measured the Upper Permian and Upper Triassic outcrop sections was evaluated on the basis of sedimentological, organic petrographic and geochemical analyses. Initial evaluations of total organic carbon contents indicated that shale samples from the Upper Permian Tuoba Formation and the Upper Triassic Adula and Duogala Formations have major source rock potential, while carbonate rocks from the Upper Triassic Bolila Formation are comparatively lean in organic matter More detailed analyses of OM-rich shale samples from the Tuoba, Adula and Duogala Formations included Rock-eval, elemental analyses, gas chromatography and organic petrography. Maceral compositions and plots of atomic O/C versus H/C indicate that the organic matter present in the samples is primarily Type II with a mixed source. Analyses of acyclic isoprenoid biomarkers indicate the organic matter was deposited under reducing and sub-to anoxic conditions. Based on the high vitrinite reflectance (Ro>1.3%) and Rock-eval data, the samples are classified as highly to over-mature, suggesting that the Tuoba, Adula and Duogaila Formation shales may generate thermogenic gas. Source rock intervals in the three formations are interpreted to have been deposited in marginal-marine environment during transgressions and under a warm and moist climatic condition.

scholarly journals Source Rock Potential of Chichali and Samana Suk Formations Deposits in Panjpir Oilfield Subsurface, Punjab Platform, Pakistan

2021 ◽  
Vol 64 (1) ◽  
pp. 59-64
Author(s):  
Syed Bilawal Ali Shah ◽  
Syed Haider Ali Shah ◽  
Adeeb Ahmed ◽  
Muhammad Nofal Munir
Keyword(s):  
Organic Carbon ◽  
Source Rock ◽  
Hydrogen Index ◽  
Indus Basin ◽  
Hydrocarbon Source Rock ◽  
Early Maturity ◽  
The Poor ◽  
Kerogen Type ◽  
Punjab Platform ◽  
Rock Eval

By using total organic carbon (TOC) and Rock-Eval pyrolysis analysis measurements, the  hydrocarbon source rock potential of Chichali and Samana Suk formations found in the subsurface of Panjpir oilfield in Punjab platform located in the eastern part of the middle Indus Basin was investigated. Twenty two core samples were collected from producing well. The analysed samples of Chichali formation contains TOC ranging between 0.99-4.61 wt.% having average TOC of 1.51 wt.% and the S2 values of Rock-Eval show the poor to fair generative potential with values ranging from 0.99-3.08 mg HC/g rock. The samples have low hydrogen index values ranging from 21-302 mg HC/g TOC and also most of the samples have low T_(max ) values ranging from 422-432 °C and have OI values ranging from 15-82 mg CO2/g TOC. Samana Suk formation samples have TOC ranging between 0.28-1.38 wt.% having average TOC of 0.84 wt.%. S2 values of Rock-Eval shows poor generative potential with values ranging from 0.05-2.99 mg HC/g rock. The samples have low hydrogen index values ranging from 13-322 mg HC/g TOC and T_(max) values ranging from 423-435 °C, and have OI values ranging from 41-182 mg CO2/g TOC. On the basis of analysis performed only one sample from Chichali and five samples of Samana Suk formations have entered early maturity zone, while all remaining samples lie in immature zone as indicated by HI vs T_(max) plot. HI vs OI plot and HI vs T_ (max) indicates the presence of kerogen Type III. All of the samples from Samana Suk formation shows poor generative potential as compared to Chichali formation having fair generative potential as indicated by S2 vs TOC plot. Hence, from the results some minor gas could be expected to have been generated from Chichali formation in Panjpir oilfield subsurface.  

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