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

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.

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Characterization of Organic Matter from Bituminous Coals of Lafia-Obi, Middle Benue Trough, Nigeria

Journal of Applied Sciences and Environmental Management ◽

10.4314/jasem.v25i5.3 ◽

2021 ◽

Vol 25 (5) ◽

pp. 701-717

Author(s):

M.U. Uzoegbu ◽

C.U. Ugwueze ◽

J.I. Nwosu

Keyword(s):

Organic Matter ◽

Vitrinite Reflectance ◽

Atomic Ratio ◽

Carbonaceous Shale ◽

Hydrocarbon Generation ◽

Oxic Condition ◽

Gaseous Hydrocarbon ◽

Benue Trough ◽

Type Iii ◽

Rock Eval

The present work deals with a study based on the geochemical techniques such as biomarkers, Rock-Eval pyrolysis, and detailed petrographic study to evaluate hydrocarbon generation potential of coal by collecting nine coal and carbonaceous shale samples from boreholes in Awgu Formation of Middle Benue Trough, Nigeria. The values vitrinite reflectance (0.94–1.15%VR) and Tmax (446–469°C) confirmed that samples are matured enough to generate liquid and gaseous hydrocarbon in coal. The coal samples also contain sufficient quantity of vitrinite and liptinite macerals varying from 70.28% to 74.10 wt%, which confirm the production of liquid hydrocarbon. The cross-plot between H/C and O/C atomic ratio indicates that samples were predominant in the bituminous rank and having kerogen Type III makes it suitable for hydrocarbon generation. Similar results were found in Rock-Eval pyrolysis analysis (Types II-III and Type III kerogen). The homohopane index (C35/C31 - C35) and homohopane ratio (C35αβS/C34αβS) range from 0.02 to 0.12 and 0.15 to 0.92 indicates oxic condition during organic matter deposition from Lafia-Obi samples. The Moretane/Hopane, Hopane/Hopane + Moretane, Ts/Ts + Tm, 22S/22S + 22RC32homohopane ratios range from 0.06 to 0.14; 0.88 to 0.94; 0.34 to 0.66; and 0.53 to 0.62 and 20S/20S+20R and αββ/αββ+ααα C29 ratios range from 0.43 to 0.58 and 0.42 to 0.55 indicate samples ar e within the late oil window/gas phase. Plots of 22S/22S+22R C32hopanes against C29αββ/αββ+ααα steranes show that Lafia-Obisamples are thermally mature.

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Modeling Hydrocarbon Generation of Deeply Buried Type Ⅲ Kerogen: A Study on Gas and Oil Potential of Lishui Sag, East China Sea Shelf Basin

Frontiers in Earth Science ◽

10.3389/feart.2020.609834 ◽

2021 ◽

Vol 8 ◽

Author(s):

Jinliang Zhang ◽

Yang Li ◽

Jinshui Liu ◽

Xue Yan ◽

Lianjie Li ◽

...

Keyword(s):

Organic Matter ◽

Source Rocks ◽

Hydrocarbon Potential ◽

Generation Model ◽

Hydrocarbon Generation ◽

Type Ii ◽

The West ◽

Organic Matter Sources ◽

Type Iii

The hydrocarbon generation model and hydrocarbon potential are investigated in the Lishui Sag, based on gold-tube pyrolysis experiments of deeply buried type Ⅲ kerogen. From this, we discuss the classification of kerogen types of source rocks with mixed organic matter sources. The hydrocarbon generated from the source rocks of the Lingfeng Formation and Yueguifeng Formation is dominated by natural gases with little oil in the West subsag, and the hydrocarbon generation model of the Lingfeng Formation is similar to that of Yueguifeng Formation, but the gas potential of Lingfeng Formation is higher than that of Yueguifeng Formation. The hydrocarbon potential of the Yueguifeng Formation in the East subsag is much higher than the West subsag, and it has considerable oil potential. Macerals diversity of source rocks is responsible for the difference of hydrocarbon generation characteristics for type Ⅲ kerogen in the Lishui Sag. It is not rigorous to evaluate the hydrocarbon potential of kerogen only based on pyrolysis parameters. Application of kerogen type index (KTI) can improve the accuracy of the classification of kerogen types with mixed organic matter sources. According to the classical kerogen classification template, the selected samples belong to type III kerogen. In this article, the selected samples were further subdivided into type III and type II/III based on the KTI value. Type III kerogen (0.5 ≤ KTI < 1.5) mainly produces gas, and type II/III kerogen (1.5 ≤ KTI < 5) mainly produces gas, but its oil potential is higher than that of type III.

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Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

Energy Exploration & Exploitation ◽

10.1177/0144598718759560 ◽

2018 ◽

Vol 36 (4) ◽

pp. 801-819 ◽

Cited By ~ 1

Author(s):

Shuangfeng Zhao ◽

Wen Chen ◽

Zhenhong Wang ◽

Ting Li ◽

Hongxing Wei ◽

...

Keyword(s):

Natural Gas ◽

Tarim Basin ◽

Oil And Gas ◽

Northwest China ◽

Source Rocks ◽

Coal Measure ◽

Hydrocarbon Generation ◽

Gas Reservoirs ◽

Isotopic Analyses ◽

Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densiﬁcation occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

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GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

African Journal of Engineering and Environment Research ◽

10.37703/ajoeer.org.ng/q2-2020/03 ◽

2020 ◽

Vol 1 (2) ◽

Keyword(s):

Source Rock ◽

Oil And Gas ◽

Linear Regression Analysis ◽

Sedimentary Basins ◽

Source Rocks ◽

Hydrocarbon Generation ◽

Good Source ◽

Type Iii ◽

Limit Value ◽

The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

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

Energy Exploration & Exploitation ◽

10.1177/0144598717753920 ◽

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.

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Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

Interpretation ◽

10.1190/int-2016-0114.1 ◽

2017 ◽

Vol 5 (2) ◽

pp. SF225-SF242 ◽

Cited By ~ 2

Author(s):

Xun Sun ◽

Quansheng Liang ◽

Chengfu Jiang ◽

Daniel Enriquez ◽

Tongwei Zhang ◽

...

Keyword(s):

Organic Matter ◽

Source Rock ◽

Ordos Basin ◽

Depositional Environments ◽

Source Rocks ◽

Type I ◽

Hydrocarbon Generation ◽

Type Ii ◽

Thermal Maturity ◽

Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

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OIL GEOCHEMISTRY AND POTENTIAL SOURCE ROCKS OF THE OFFICER BASIN, SOUTH AUSTRALIA

The APPEA Journal ◽

10.1071/aj79006 ◽

1980 ◽

Vol 20 (1) ◽

pp. 68 ◽

Cited By ~ 3

Author(s):

D.M. McKirdy ◽

A.J. Kantsler

Keyword(s):

Organic Matter ◽

Organic Carbon ◽

Carbonate Rocks ◽

Depositional Environment ◽

South Australia ◽

Source Rocks ◽

Potential Source ◽

Playa Lake ◽

Oil Source ◽

Extractable Organic Matter

Oil shows observed in Cambrian Observatory Hill Beds, intersected during recent stratigraphic drilling of SADME Byilkaoora-1 in the Officer Basin, indicate that oil has been generated within the basin. Shows vary in character from "light" oils exuding from fractures through to heavy viscous bitumen in vugs in carbonate rocks of a playa-lake sequence.The oils are immature and belong to two primary genetic families with some oils severely biodegraded. The less altered oils are rich in the C13 - C25 and C30 acyclic isoprenoid alkanes. Source beds within the evaporitic sequence contain 0.5 - 1.0% total organic carbon and yield up to 1900 ppm solvent-extractable organic matter. Oil-source rock correlations indicate that the oils originated within those facies drilled; this represents the first reported examples of non-marine Cambrian petroleum. The main precursor organisms were benthonic algae and various bacteria.Studies of organic matter in Cambrian strata from five other stratigraphic wells in the basin reveal regional variations in hydrocarbon source potential that relate to differences in precursor microbiota and/or depositional environment and regional maturation. Micritic carbonates of marine sabkha origin, located along the southeast margin of the basin, are rated as marginally mature to mature and good to prolific sources of oil. Further north and adjacent to the Musgrave Block, Cambrian siltstones and shales have low organic carbon values and hydrocarbon yields, and at best are only marginally mature. Varieties of organic matter recognised during petrographic studies of carbonates in the Officer Basin include lamellar alginite (alginite B) and "balls" of bitumen with reflectance in the range 0.2 to 1.4%.

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Geochemical characterization of hydrocarbon source rocks of the Triassic-Jurassic time interval in the Mandawa basin, southern Tanzania: Implications for petroleum generation potential

South African Journal of Geology ◽

10.25131/sajg.123.0037 ◽

2020 ◽

Vol 123 (4) ◽

pp. 587-596

Author(s):

A. Emanuel ◽

C.H. Kasanzu ◽

M. Kagya

Keyword(s):

Source Rocks ◽

Geochemical Data ◽

Time Interval ◽

Type I ◽

Hydrocarbon Generation ◽

Type Ii ◽

Geochemical Characterization ◽

Type Iii ◽

Petroleum Generation

Abstract Triassic to mid-Jurassic core samples of the Mandawa basin, southern Tanzania (western coast of the Indian Ocean), were geochemically analyzed in order to constrain source rock potentials and petroleum generation prospects of different stratigraphic formations within the coastal basin complex. The samples were collected from the Mihambia, Mbuo and Nondwa Formations in the basin. Geochemical characterization of source rocks intersected in exploration wells drilled between 503 to 4042 m below surface yielded highly variable organic matter contents (TOC) rated between fair and very good potential source rocks (0.5 to 8.7 wt%; mean ca. 2.3 wt%). Based on bulk geochemical data obtained in this study, the Mandawa source rocks are mainly Type I, Type II, Type III, mixed Types II/III and Type IV kerogens, with a predominance of Type II, Type III and mixed Type II/III. Based on pyrolysis data (Tmax 417 to 473oC; PI = 0.02 to 0.47; highly variable HI = 13 to 1 000 mg/gTOC; OI = 16 to 225 mg/g; and VR values of between 0.24 to 0.95% Ro) we suggest that the Triassic Mbuo Formation and possibly the mid-Jurassic Mihambia Formation have a higher potential for hydrocarbon generation than the Nondwa Formation as they are relatively thermally mature.

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

Journal of Geochemistry ◽

10.1155/2015/809780 ◽

2015 ◽

Vol 2015 ◽

pp. 1-11 ◽

Cited By ~ 1

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.

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Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine)

Geologica Carpathica ◽

10.2478/v10096-012-0025-3 ◽

2012 ◽

Vol 63 (4) ◽

pp. 319-333 ◽

Cited By ~ 6

Author(s):

Paweł Kosakowski ◽

Dariusz Więcław ◽

Adam Kowalski ◽

Yuriy Koltun

Keyword(s):

Organic Matter ◽

Middle Jurassic ◽

Sedimentary Cover ◽

Source Rocks ◽

Hydrocarbon Potential ◽

Hydrocarbon Generation ◽

Hydrocarbon Source Rock ◽

Core Samples ◽

Se Poland ◽

Geochemical Parameters

Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine) The Jurassic/Cretaceous stratigraphic complex forming a part of the sedimentary cover of both the eastern Małopolska Block and the adjacent Łysogóry-Radom Block in the Polish part as well as the Rava Rus'ka and the Kokhanivka Zones in the Ukrainian part of the basement of the Carpathian Foredeep were studied with geochemical methods in order to evaluate the possibility of hydrocarbon generation. In the Polish part of the study area, the Mesozoic strata were characterized on the basis of the analytical results of 121 core samples derived from 11 wells. The samples originated mostly from the Middle Jurassic and partly from the Lower/Upper Cretaceous strata. In the Ukrainian part of the study area the Mesozoic sequence was characterized by 348 core samples collected from 26 wells. The obtained geochemical results indicate that in both the south-eastern part of Poland and the western part of Ukraine the studied Jurassic/Cretaceous sedimentary complex reveals generally low hydrocarbon source-rock potential. The most favourable geochemical parameters: TOC up to 26 wt. % and genetic potential up to 39 mg/g of rock, were found in the Middle Jurassic strata. However, these high values are contradicted by the low hydrocarbon index (HI), usually below 100 mg HC/g TOC. Organic matter from the Middle Jurassic strata is of mixed type, dominated by gas-prone, Type III kerogen. In the Polish part of the study area, organic matter dispersed in these strata is generally immature (Tmax below 435 °C) whereas in the Ukrainian part maturity is sufficient for hydrocarbon generation.

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