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 Characterization of organic matter from a stratigraphic sequence intercepted by the Nemo-1X well, Mozambique: Potential for hydrocarbon generation

2018 ◽  
Vol 36 (5) ◽  
pp. 1157-1171
Author(s):  
Agostinho Mussa ◽  
Deolinda Flores ◽  
Joana Ribeiro ◽  
Ana MP Mizusaki ◽  
Mónica Chamussa ◽  
...  
Keyword(s):  
Organic Matter ◽  
Organic Carbon ◽  
Total Organic Carbon ◽  
Hydrocarbon Exploration ◽  
Published Data ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Offshore Area ◽  
Type Iii ◽  
Kerogen Type

The Mozambique Basin, which occurs onshore and offshore in the central and southern parts of Mozambique, contains a thick sequence of volcanic and sedimentary rocks that range in age from the Jurassic to Cenozoic. This basin, along with the Rovuma basin to the north, has been the main target for hydrocarbon exploration; however, published data on hydrocarbon occurrences do not exist. In this context, the present study aims to contribute to the understanding of the nature of the organic matter of a sedimentary sequence intercepted by the Nemo-1X exploration well located in the offshore area of the Mozambique Basin. The well reached a depth of 4127 m, and 33 samples were collected from a depth of 2219–3676 m ranging in age from early to Late Cretaceous. In this study, petrographic and geochemical analytical methods were applied to assess the level of vitrinite reflectance and the organic matter type as well as the total organic carbon, total sulfur, and CaCO3 contents. The results show that the total organic carbon content ranges from 0.41 to 1.34 wt%, with the highest values determined in the samples from the Lower Domo Shale and Sena Formations, which may be related to the presence of the solid bitumens that occur in the carbonate fraction of those samples. The vitrinite random reflectances range from 0.65 to 0.86%Rrandom, suggesting that the organic matter in all of the samples is in the peak phase of the “oil generation window” (0.65–0.9%Rrandom). The organic matter is mainly composed of vitrinite and inertinite macerals, with a minor contribution of sporinite from the liptinite group, which is typical of kerogen type III. Although all of the samples have vitrinite reflectances corresponding to the oil window, the formation of liquid hydrocarbons is rather limited because the organic matter is dominated by gas-prone kerogen type III.

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 Depositional environment and burial history of a Lower Cretaceous carbonaceous claystone, Bornholm, Denmark

1996 ◽  
Vol 43 ◽  
pp. 133-142
Author(s):  
H. I. Petersen ◽  
J. A. Bojesen Koefoed ◽  
H. P. Nytoft
Keyword(s):  
Organic Matter ◽  
Lower Cretaceous ◽  
Depositional Environment ◽  
Lower Jurassic ◽  
Plant Litter ◽  
Burial History ◽  
Transport Distance ◽  
Geochemical Parameters ◽  
Kerogen Type ◽  
History Of

A c. 1 m thick carbonaceous claystone from the type locality of the Lower Cretaceous Skyttegård Member (Rabekke Formation), Bornholm, has been investigated by organic pétrographie and organic geochemical methods in order to assess the depositional environment of the claystone and the thermal maturity of the organic matter. The claystone was deposited in a low-energy, anoxic lake which occasionally was marine influenced. The organic matter is terrestrial and can be classified as kerogen type III and lib. Detrital organic matter and cutinite are characteristic components. The organic matter is allochthonous but the transport distance was short, and the plant material was probably mainly derived from plants growing at the edge of, or nearto, the lake. Source-specific biomarkers such as norisopimarane suggest that the plant litter was derived from a gymnospermous, low-diversity vegetation. Evidence for early angiospermous plants cannot be demonstrated with any certainty. A huminite reflectance value of 0.24%Rm and several geochemical parameters indicate that the organic matter is highly immature. It has only experienced coalification corresponding to the peat stage. Estimates show that, prior to uplift, the claystone was buried to a maximum of approximately 260 m. Reflectance data further suggest that a maximum c. 550 m thick sediment package was removed by erosion prior to deposition of the ?uppermost Jurassic-Lower Cretaceous sediments on Lower Jurassic strata.

scholarly journals Organic Geochemistry and Source Rock Potential of Naokelekan Formation in Selected Wells, North Iraq

2018 ◽  
Vol 5 (1) ◽  
pp. 8-14
Author(s):  
Jan I. Ismael
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Organic Geochemistry ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Type Iv ◽  
Kerogen Type ◽  
Bituminous Rock ◽  
North Iraq ◽  
Bituminous Shale

In this study, organic geochemical characteristics and potential of Upper Oxfordian–Lower Kimmeridgian aged bituminous shale beds in Naokelekan formation (North Iraq) were investigated by using TOC and pyrolysis analyses. The Total Organic Carbon (TOC) contents for the studied samples varying between from 0.46-21.33%, average 7.06% and Taq Taq-1 well as good hydrocarbon potential (0.85-1.66 %, with average of 1.06%), whereas Jk-1 well can be rated as an very good hydrocarbon potential from 1.04-4.16 %, with average of 2.15 %. The low Hydrogen Index (HI = 24-605 mg HC/g TOC) for Bj-1 well, (HI = 147-673 mg HC/g TOC) in the Jk-1 well while in Taq Taq-1 well (HI = 9-48 mg HC/g TOC) indicate that kerogen type for the vast majority of the studied samples is Type II/I for Bj-1 well and Type IV with few samples, Type of I and II kerogens in the Taq Taq-1 and Jk-1 well. Consequently most of the organic matter of Bj-1 and Jk-1 well tends to generate petrol, even though a small portion of them exhibit a tendency to generate gas. While all samples of Taq Taq-1 well tends to generate gas. The studied bituminous rock samples characterized by low Tmax (434-602 °C) for Bj-1,Taq Taq-1 (344-429 °C) and (419-602 °C) for Jk-1 well. These values show, in terms of potential of hydrocarbon generation, that the studied samples have a source rock potential of organic matter from immature to over mature. Additionally, the S1 hydrocarbon type values indicate no external contribution of migrated hydrocarbons to the bituminous rocks of the studied area.

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 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 evaluation of the carbonaceous shale of the upper cretaceous Anambra Basin for potential gas generation, Nigeria

2021 ◽  
Vol 14 (6) ◽  
Author(s):  
George Oluwole Akintola ◽  
Phillips Reuben Ikhane ◽  
Francis Amponsah-Dacosta ◽  
Ayoade Festus Adeagbo ◽  
Sphiwe Emmanuel Mhlongo ◽  
...  
Keyword(s):  
Organic Matter ◽  
Natural Gas ◽  
Source Rocks ◽  
Carbonaceous Shale ◽  
Hydrocarbon Generation ◽  
Petrophysical Parameters ◽  
Type Iii ◽  
Anambra Basin ◽  
Geochemical Evaluation ◽  
Extractable Organic Matter

AbstractThe rise in demand for natural gas has spurred the need to investigate the inland sedimentary basin for more potential sources. In response, the petrophysical parameters of the carbonaceous shale samples from two deep boreholes of Anambra Basin were evaluated. The gas-prone nature of Nkporo shale showed a thermal evolution of a Type III kerogen with initial HI value between 650 and 800 mgHC/gTOC, S2/S3 < 1, a maximum Tmax value of 488°C and have a low hydrocarbon generation potential ranging from 0.07 to 0.15. However, the average TOC content (2.21 wt%) indicated a good source rocks for hydrocarbon since it exceeds threshold limit of 0.5%. The plot of HI against Tmax shows that the organic matter belongs to the Type-III kerogen which reflects the capability of the Npkoro Formation to generate more natural gas than oil compared to Type-II kerogen. The high values (>3) of pristane/phytane ratio in both wells indicated that the organic matter belongs to terrigenous source deposited under anoxic condition which is typical of non-marine shale. The presence of Oleanane content in the Cretaceous shale sediments indicated the contribution of cell wall and woody plant tissues from the terrestrial higher plant. The low concentrations of extractable organic matter (EOM) present in form of isoprenoid and aliphatic hydrocarbon indicated little or no bitumen extract from the studied shale. Considering the high carbon preference indices (CPI) value greater than 1, the preponderance of vitrinite organic macerals and other favourable aforementioned petrophysical parameters, the non-marine Npkoro Shale Basin has significant potential to generate and expel natural gas apart from the current marine basins.

scholarly journals Chronostratigraphy, palynofacies, source-rock potential, and organic thermal maturity of Jurassic rocks from Qatar

GeoArabia ◽  
2002 ◽  
Vol 7 (4) ◽  
pp. 675-696
Author(s):  
Mohamed I. A. Ibrahim ◽  
Hamad Al-Saad ◽  
Suzan E. Kholeif
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Reservoir Rock ◽  
Inert Material ◽  
Type I ◽  
Carbonate Sediments ◽  
Type Ii ◽  
Type Iii ◽  
Kerogen Type ◽  
Marine Algal

ABSTRACT Strontium isotope, palynological, and total organic carbon (TOC) analyses were made on core samples from the Izhara, Araej, and Hanifa formations of three wells in onshore Qatar. Eleven samples were analyzed for their 87Sr/86Sr ratios. The results gave a chronostratigraphic range of Early Jurassic (Hettangian) to Late Jurassic (Oxfordian), with an overall age range of 202.4 Ma to 157.8 Ma. Maximum flooding surfaces MFS J10 to MFS J50 occur in the Izhara, Araej, and Hanifa formations. The organic matter in the carbonate sediments of the Izhara, Araej, and Hanifa formations was almost exclusively of marine algal origin dominated by marine microplankton. Organic matter obtained from the Izhara Formation was mature to over-mature kerogen type-III to IV, gas-prone to inert material (mean TOC 0.31%). In the Araej Formation, mature oil-prone and gas-prone kerogen type-II and type-III organic matter occurred in both the lower and upper Araej members (TOC 0.13-0.69%). The stylolitic limestone of the Uwainat member of the Araej Formation has poor potential as a source rock for petroleum (TOC 0.03-0.13%), but is considered to be the main reservoir rock of the Middle Jurassic in Qatar. Mature, highly oil-prone organic matter (type-I and type-II kerogen) was present in black limestone of the Hanifa Formation (mean TOC 0.60%; maximum 0.93%). The limestone is considered to be the most likely petroleum source rock for the underlying and overlying limestone reservoirs of the Uwainat member of the Araej Formation (Bathonian) and the Arab-D member of the Arab Formation (Kimmeridgian) units, respectively.

Labelling of non-A, non-B hepatitis infected chimpanzee hepatocytes with nuclease-gold conjugates

1984 ◽  
Vol 42 ◽  
pp. 250-251
Author(s):  
G. D. Gagne ◽  
M. F. Miller ◽  
D. A. Peterson
Keyword(s):  
Endoplasmic Reticulum ◽  
Experimental Infection ◽  
Uranyl Acetate ◽  
Type I ◽  
Cellular Injury ◽  
Type Ii ◽  
Tubular Structures ◽  
Type Iii ◽  
Type Iv ◽  
Infected Chimpanzee

Experimental infection of chimpanzees with non-A, non-B hepatitis (NANB) or with delta agent hepatitis results in the appearance of characteristic cytoplasmic alterations in the hepatocytes. These alterations include spongelike inclusions (Type I), attached convoluted membranes (Type II), tubular structures (Type III), and microtubular aggregates (Type IV) (Fig. 1). Type I, II and III structures are, by association, believed to be derived from endoplasmic reticulum and may be morphogenetically related. Type IV structures are generally observed free in the cytoplasm but sometimes in the vicinity of type III structures. It is not known whether these structures are somehow involved in the replication and/or assembly of the putative NANB virus or whether they are simply nonspecific responses to cellular injury. When treated with uranyl acetate, type I, II and III structures stain intensely as if they might contain nucleic acids. If these structures do correspond to intermediates in the replication of a virus, one might expect them to contain DNA or RNA and the present study was undertaken to explore this possibility.

scholarly journals Effective source rock selection and oil–source correlation in the Western Slope of the northern Songliao Basin, China

2021 ◽  
Vol 18 (2) ◽  
pp. 398-415
Author(s):  
He Bi ◽  
Peng Li ◽  
Yun Jiang ◽  
Jing-Jing Fan ◽  
Xiao-Yue Chen
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Thermal Evolution ◽  
Songliao Basin ◽  
Source Rocks ◽  
Crude Oils ◽  
Western Slope ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

AbstractThis study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

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