scholarly journals Source rock geochemistry of shale samples from Ege-1 and Ege-2 wells, Niger Delta, Nigeria

2020 ◽  
Author(s):  
S. L. Fadiya ◽  
S. A. Adekola ◽  
B. M. Oyebamiji ◽  
O. T. Akinsanpe
Keyword(s):  
Source Rock ◽  
Niger Delta ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Early Maturity ◽  
Type Iii ◽  
Niger Delta Basin ◽  
Rock Eval

AbstractSelected shale samples within the middle Miocene Agbada Formation of Ege-1 and Ege-2 wells, Niger Delta Basin, Nigeria, were evaluated using total organic carbon content (TOC) and Rock–Eval pyrolysis examination with the aim of determining their hydrocarbon potential. The results obtained reveal TOC values varying from 1.64 to 2.77 wt% with an average value of 2.29 wt% for Ege-1 well, while Ege-2 well TOC values ranged from 1.27 to 3.28 wt% (average of 2.27 wt%) values which both fall above the minimum threshold (0.5%) for hydrocarbon generation potential in the Niger Delta. Rock–Eval pyrolysis data revealed that the shale source rock samples from Ege-1 well are characterized by Type II–Type III kerogens which are thermally mature to generate oil or gas/oil. The Ege-2 well pyrolysis result showed that some of the ditch cutting samples are comprised of Type II (oil prone) and Type III (gas-prone kerogen) which are thermally immature to marginal maturity (Tmax 346–439 °C). This study concludes that the shale intercalations between reservoir sands of the Agbada Formation are good source rocks in early maturity and also must have contributed to the vast petroleum reserve in the Niger Delta Basin because of the subsidence of the basin.

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

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.

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

2017 ◽  
Vol 5 (2) ◽  
pp. SF225-SF242 ◽  
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.

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

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.

The coupled generation of organic acids and hydrocarbons during source rock maturation

2020 ◽  
Author(s):  
Jian Chen ◽  
Jie Xu ◽  
Zhenyu Sun ◽  
Susu Wang ◽  
Wanglu Jia ◽  
...  
Keyword(s):  
Organic Acids ◽  
Source Rock ◽  
Maximum Yield ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Pore Waters ◽  
Reservoir Properties ◽  
Type Iii ◽  
Short Period

&lt;p&gt;&lt;strong&gt;Introduction: &lt;/strong&gt;Organic acids which are commonly detected in oilfield waters, can partially enhance reservoir properties. Previous studies have suggested that cleavage of the oxygen-containing functional group in kerogen is a major source of organic acids. However, this cleavage is assumed to occur before the source rock enters the oil window. If this is correct, then these acids can dissolve only minerals in the source rocks. Presently, no detailed study of the generation of organic acids during the whole thermal maturation of source rocks has been conducted. It is unclear whether organic acids could migrate into reservoirs.&lt;/p&gt;&lt;p&gt;&lt;strong&gt;Aim: &lt;/strong&gt;This research simulated the thermal evolution of source rocks in order to build a coupled model of organic acid and hydrocarbon generation, and investigate if organic acids generated in source rocks can migrate into reservoirs.&lt;/p&gt;&lt;p&gt;&lt;strong&gt;Methods: &lt;/strong&gt;Three immature source rocks containing type I, II, and III kerogens were crushed to 200 mesh. These powders, along with deionized water, were sealed in Au tubes and heated to 220&amp;#8211;360&amp;#176;C for 72 h (EasyRo 0.37-1.16%). All the run products, including organic acids, gas, and bitumen, were analyzed.&lt;/p&gt;&lt;p&gt;&lt;strong&gt;Results: &lt;/strong&gt;At all temperatures, the organic acids dissolved in the waters are composed of formate, acetate, propionate, and oxalate. Acetate is the major compound with a modal proportion of &gt;83%. The maximum yield of total organic acids was from source rocks containing type I kerogen (31.0 mg/g TOC), which was twice that from source rocks containing type II and III kerogens (13.3&amp;#8211;15.4 mg/g TOC). However, for the type I and II kerogen-bearing source rocks, the organic acids reached a maximum yield (EasyRo = 1.16%) following the bitumen generation peak (EasyRo = 0.95%). Organic acids from type III kerogen-bearing source rocks reached their maximum yield (EasyRo = 0.95%) before the source rock entered the gas window (EasyRo &gt; 1.16%).&lt;/p&gt;&lt;p&gt;&lt;strong&gt;Conclusions: &lt;/strong&gt;Our data suggest that the generation of organic acids is coupled with the generation of oil from type I and II kerogen-bearing source rocks, but form earlier than gas from type III kerogen-bearing source rocks. As such, some organic acids dissolved in pore waters are possibly expelled from source rocks containing type I and II kerogen with oils, which can then migrate into reservoirs. Migration of organic acids into reservoirs from source rocks containing type III kerogen is also possible in some situations. For example, when a source rock is rapidly buried for a short period, such as in the Kuqa Depression, Tarim Basin, China, the generation interval of organic acids and gas is short. Both could be expelled outside and migrate upwards into reservoirs. In conclusion, organic acids derived from source rocks can contribute to reservoir alteration.&lt;/p&gt;

A practical petrophysical model for a source rock play: The Mancos Shale

2017 ◽  
Vol 5 (3) ◽  
pp. T423-T435
Author(s):  
Jesús M. Salazar ◽  
Ron J. M. Bonnie ◽  
William W. Clopine ◽  
G. Eric Michael
Keyword(s):  
Source Rock ◽  
Water Saturation ◽  
Clay Content ◽  
Source Rocks ◽  
Crushed Rock ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Niobrara Formation ◽  
Mancos Shale ◽  
Petrophysical Model

Recently, the focus in source rock exploration has moved from gas-rich to liquid-rich plays and warrants revisiting “bypassed” hydrocarbon charged source rocks, which were deemed uneconomic when first drilled. In North America’s oil fields, there are thousands of wells with different vintages of nuclear and electrical logs, yet these wells generally lack any advanced logs beyond the traditional triple combo. We have developed a workflow that uses a considerable amount of laboratory measurements made on crushed rock to upscale a petrophysical model based on a triple combo logging suite only. The model divides the field (laterally) in oil window and gas window fairways and (vertically) in petrophysical units. The remaining hydrocarbon generation potential is based on geochemical measurements, such as thermal maturity and total organic carbon content (TOC), from core and cuttings in the area. The petrophysical units reflect major geologic intervals with similar porosity and clay content. The workflow was sequentially built by correlating logs with core measurements, using TOC and maturity for organic matter, X-ray diffraction for mineralogy and grain density, porosity, and water saturation from fluids extraction, for volumetrics. The model is applied to the Mancos Shale (New Mexico, USA), a Cretaceous-age source rock, which includes the Niobrara Formation. The Mancos Shale has been penetrated in various fields while developing conventional sandstone reservoirs. The model is validated with measurements on a core recently acquired in the anticipated high-hydrocarbon-yield window. Petrophysical properties predicted from logs agree well with core measurements in blind tests, demonstrating the robustness of the model despite being based on a basic suite of logs and a simple deterministic approach. This model is now routinely used by the asset team as an automated workflow to generate fairway maps, locate sweet spots, and for landing lateral wells.

scholarly journals Source rock potential of the Late Miocene Metochia formation of Gavdos Island, Greece

2017 ◽  
Vol 47 (2) ◽  
pp. 871
Author(s):  
I. Pyliotis ◽  
A. Zelilidis ◽  
N. Pasadakis ◽  
G. Panagopoulos ◽  
E. Manoutsoglou
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Late Miocene ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Low Oxygen ◽  
Crete Island ◽  
Good Potential ◽  
The Rich ◽  
Rock Eval

Rock-Eval method was used to analyze 53 samples from late Miocene Metochia Formation of Gavdos Island (south of Crete Island) in order to characterize the contained organic matter and to evaluate its potential as source rock. The samples were collected from Metochia Section which consists of about 100 m thick marlssapropels alternations. Organic matter analysis showed that the studied succession could be subdivided into two parts. The lower one, which is generally rich in organic matter and the upper one, which is poor. In the lower part the rich horizons in organic matter are characterized by Kerogen type II, III and IV, with low oxygen content, and with fair to very good potential for gas and/or oil hydrocarbon generation. Additionally, the studied samples are thermally immature. Taking into account that the studied area has never been buried in such a depth to reach conditions of maturation, as well as, that the studied section in Gavdos is connected with Messara basin located in the northeastern and, finally, that the main part of Gavdos basin, which is situated between Gavdos and Crete islands, has continuously encountered subsidence, we could conclude that sediments of Metochia Formation could act as source rocks but in the more deep central part of the Gavdos basin.

scholarly journals Origins of hydrocarbons in the Geneva Basin: insights from oil, gas and source rock organic geochemistry

2021 ◽  
Vol 114 (1) ◽  
Author(s):  
Damien Do Couto ◽  
Sylvain Garel ◽  
Andrea Moscariello ◽  
Samer Bou Daher ◽  
Ralf Littke ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Oil And Gas ◽  
Organic Geochemistry ◽  
Source Rocks ◽  
Type Ii ◽  
Dominant Type ◽  
Type Iii ◽  
North Alpine Foreland Basin ◽  
Migration Pathways

AbstractAn extensive subsurface investigation evaluating the geothermal energy resources and underground thermal energy storage potential is being carried out in the southwestern part of the Swiss Molasse Basin around the Geneva Canton. Among this process, the evaluation of the petroleum source-rock type and potential is an important step to understand the petroleum system responsible of some oil and gas shows at surface and subsurface. This study provides a first appraisal of the risk to encounter possible undesired occurrence of hydrocarbons in the subsurface of the Geneva Basin. Upon the numerous source-rocks mentioned in the petroleum systems of the North Alpine Foreland Basin, the marine Type II Toarcian shales (Lias) and the terrigenous Type III Carboniferous coals and shales have been sampled from wells and characterized with Rock–Eval pyrolysis and GC–MS analysis. The Toarcian shales (known as the Posidonia shales) are showing a dominant Type II organic matter composition with a Type III component in the Jura region and the south of the basin. Its thermal maturity (~ 0.7 VRr%) shows that this source-rock currently generates hydrocarbons at depth. The Carboniferous coals and shales show a dominant Type III organic matter with slight marine to lacustrine component, in the wet gas window below the Geneva Basin. Two bitumen samples retrieved at surface (Roulave stream) and in a shallow borehole (Satigny) are heavily biodegraded. Relative abundance of regular steranes of the Roulave bitumen indicates an origin from a marine Type II organic matter. The source of the Satigny bitumen is supposedly the same even though a deeper source-rock, such as the lacustrine Permian shales expelling oil in the Jura region, can’t be discarded. The oil-prone Toarcian shales in the oil window are the most likely source of this bitumen. A gas pocket encountered in the shallow well of Satigny (Geneva Canton), was investigated for molecular and stable isotopic gas composition. The analyses indicated that the gas is made of a mixture of microbial (very low δ13C1) and thermogenic gas. The isotopic composition of ethane and propane suggests a thermogenic origin from an overmature Type II source-rock (> 1.6 VRr%) or from a terrigenous Type III source at a maturity of ~ 1.2 VRr%. The Carboniferous seems to be the only source-rock satisfying these constraints at depth. The petroleum potential of the marine Toarcian shales below the Geneva Basin remains nevertheless limited given the limited thickness of the source-rock across the area and does not pose a high risk for geothermal exploration. A higher risk is assigned to Permian and Carboniferous source-rocks at depth where they reached gas window maturity and generated large amount of gas below sealing Triassic evaporites. The large amount of faults and fractures cross-cutting the entire stratigraphic succession in the basin certainly serve as preferential migration pathways for gas, explaining its presence in shallow stratigraphic levels such as at Satigny.

scholarly journals Hydrocarbon-Generating Potential of Eocene Source Rocks in the Abakaliki Fold Belt, Nigeria / Potencial za nastanek oglikovodikov v eocenskih izvornih kamninah nariva Abakaliki

2020 ◽  
Vol 66 (4) ◽  
pp. 223-233
Author(s):  
O.A. Oluwajana ◽  
A.O. Opatola ◽  
O.B. Ogbe ◽  
T.D. Johnson
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Threshold Value ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Fold Belt ◽  
Gaseous Hydrocarbon ◽  
Geochemical Model ◽  
The One ◽  
Rock Eval

AbstractSubsurface information on source rock potential of the Eocene shale unit of the Abakaliki Fold Belt is limited and has not been widely discussed. The total organic carbon (TOC) content and results of rock-eval pyrolysis for nine shale samples, as well as the one-dimensional (1D) geochemical model, from an exploration well in the Abakaliki Fold Belt were used to evaluate the source rock potentials and timing of hydrocarbon generation of Lower Eocene source rocks. The TOC content values of all the samples exceeded the minimum threshold value of 0.5 wt.% required for potential source rocks. A pseudo-Van Krevelen plot for the shale samples indicated Type II–III organic matter capable of generating gaseous hydrocarbon at thermally mature subsurface levels. The 1D burial model suggests that the Eocene source rock is capable of generating oil and gas at the present time. The modelled transformation ratio trend indicates that a fair amount of hydrocarbon has been expelled from the source rocks. The results of this study indicate that the Eocene source units may have charged the overlying thin Eocene sand bodies of the Abakaliki Fold Belt.

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