by Lucas F.A and Omodolor Hope E
Original Research
One hundred and ninety (190) ditch cutting samples of depth range within 20ft- 11820ft (6.09m-3603.7m) from X2 Well Greater Ughelli DepoBelt, Niger Delta Basin were subjected to palynological and palynofacies analysis combined with sedimentological studies, with a view to define its organic thermal maturation and source rock potential. The analysis of the ditch cutting samples were carried out using reflected light microscope for lithologic description while the palynofacies analysis was carried out using transmitted light microscope. The sedimentological analysis reveals forty-nine (49) lithozones and seven (7) lithofacies units, which were deduced based on their mineralogical composition, textural properties, fossil content, homogeneity and heterogeneity of the lithofacies units. The major lithofacies units penetrated in the well are sandstone, shaly sand, sandy shale, clay, sandy clay, clayey sand and shale. Its associated minerals include quartz, feldspar, calcium carbonate and glauconite. Identification of the petroleum play elements and hydrocarbon potential of the X2 Well were equally established. The result from the palynofacies analysis reveals miospores (pollen and spores), woody plant materials (black wood and phytoclast), amorphous organic matter which were used to characterize the well of its kerogen type and maturity. Fifty (50) lithofacies units were subjected to palynofacies analysis, this indicates a potential for hydrocarbon generation. Presence of the dark brown to black wood plant material (black wood and phytoclast) suggest gas-prone for this well. However, the high abundance of light brown to brown colour index of spore/pollen shows that the organic matter of X2 Well falls within the zone of mature main phase liquid hydrocarbon generation (Spore Color Index of 4-6). Palynofacies analysis of X2 Well shows that the well can yield about 70% of oil and 30% of gas (kerogen type II).
Journal of Geosciences and Geomatics. 2018, 6(2), 85-93. DOI: 10.12691/jgg-6-2-6
Pub. Date: August 17, 2018
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by Lucas F.A and Omodolor Hope E
Original Research
One hundred and ninety (190) ditch cutting samples of depth range within 20 ft-11820 ft (6.09m-3603.7m) from X2 Well Greater Ughelli Depo Belt, Niger Delta Basin were subjected to sedimentological analysis, with a view to characterizing the sedimentary succession penetrated by the drill. The ditch cutting samples were analyzed using reflected light microscope for lithologic description. The sedimentological analysis reveals forty nine (49) lithozones and seven (7) lithofacies units, deduced based on their mineralogical composition; textural properties; fossil content; and the homogeneity and heterogeneity of the lithofacies units. The major lithofacies units penetrated in the well are sandstone, shaly sand, sandy shale, clay, sandy clay, clayey sand and shale. Its associated minerals include quartz, feldspar and glauconite. Identification of the petroleum play elements and hydrocarbon potential of the X2Well were equally proposed in the Agbada formation within depth (1371.9m – 3603.7m) containing two (2) probable reservoir rocks (Zone 7, with thickness 18.3 meters and zone 15 with thickness 146.4 meters) and six (6) probable source rocks (Zone 2, 4, 6, 8, 10, 12).
Journal of Geosciences and Geomatics. 2018, 6(2), 77-84. DOI: 10.12691/jgg-6-2-5
Pub. Date: August 17, 2018
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by Gus Djibril KOUANKAP NONO, Pierre WOTCHOKO, Alice MAGHA, Sylvestre GANNO, Ndam NJOYA, Aloysius AFAHNWIE NGAMBU, Jean Paul NZENTI and Veronique KAMGANG KABEYENE
Original Research
The basement rocks of Bamenda town are mainly covered by volcanic rocks and are made up of two distinct types of granitoids: granites and leucogranites. These basement rocks belong geochemically to the same granite field. The studied granitoids are silica rich, with concentrations ranging from 70 to 73% in granite and 73 to 76% in leucogranite. Both belong to high-K calc-alcaline series with granite being magnesian and more potassic (Na2O/K2O < 1) whereas the leucogranite is ferriferous and similar to Na-granitoids (Na2O/K2O >1). Leucogranites are low Ba-Sr granitoids, strongly peraluminous (A/CNK > 1.1) and plot in the field of S-type granites, while granites are high Ba-Sr granitoids, slightly peraluminous and plot in the field of I-type granitoids. The chondrite-normalized REE patterns show more LREE enrichment in granites (>100*chondrite) than in leucogranites (>10*chondrite). Major and trace element compositions of the leucogranites and granites indicate crustal derivation from the partial melting of metapelite and metagreywacke respectively. The REE patterns display pronounced negative Eu anomalies (Eu/Eu* = 0.23-0.36) in leucogranites due to low degree of partial melting of a plagioclase depleted crustal source, and weakly negative to null Eu anomalies (Eu/Eu* = 0.81-1.08) in granites due to high degree of partial melting. The estimated temperatures of Bamenda granitoids magma range between 800°C and 950°C. Bamenda I-type granites are syn-tectonic and are similar to the other granitoids of the central domain of the Pan-African North-Equatorial Fold belt in Cameroon. Bamenda S-type peraluminous leucogranites are post-tectonic and chemically similar to the Himalayan peraluminous leucogranites. Furthermore, decompression model may be related to Bamenda leucogranite formation. Tectonically, the studied granitoids are related to crustal delamination characterizing the post-collisional event within the Pan African Fold Belt.
Journal of Geosciences and Geomatics. 2018, 6(2), 65-76. DOI: 10.12691/jgg-6-2-4
Pub. Date: August 13, 2018
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by M. K. Salami, A. Amuni, T. Adewumi, J. Asare and O. K. Oyewole
Original Research
This paper presents the results of the reservoir characterization of Baze field, Niger Delta, Nigeria, using seismic and well log data. The area of the field is bounded with longitudes 3.000 E and 7.000 E, and latitudes 4.000 N and 8.000 N. Analysis of the structural maps of five horizons showed the structural geometry of the subsurface and the presence of possible trapping mechanism, which control the accumulation of hydrocarbons in the Baze field. Interpretations of faults that described the structural setting of the field showed two major faults trends from East to West whiles dipping southward with other minor (synthetic and antithetic) faults. Petrophysical parameters are estimated to determine reservoir properties, while the hydrocarbon volumetric reserves are calculated with total oil and gas recoverable estimates of 6.115 MMbbls and 8.456 Bscf respectively. From the reservoir characterizations done in this research work, the Baze field located onshore of the Niger Delta has been identified as suitable for hydrocarbon production.
Journal of Geosciences and Geomatics. 2018, 6(2), 55-64. DOI: 10.12691/jgg-6-2-3
Pub. Date: July 23, 2018
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by Saha Fouotsa Alliance Nicaise, Tchameni Rigobert, Nomo Negue Emmanuel, Daouda Dawaï, Penaye Joseph and Fosso Tchunte Periclex Martial
Original Research
Field petrographic and structural data of the Mbé-Sassa-Bersi area exposed two main group of rock (metamorphics and plutonics) which were affected by polyphase deformation. The structural evolution is marked by four deformation phases called D1, D2, D3 and D4. The geometrical arrangement of D1 structures (flat-lying foliation, horizontal lineation, recumbent folds and overlapping) allow to linked this deformation phase to tectonic nappe verging toward SSE. The second deformation stage (D2) corresponds to simple shear dominated transpression and characterized by the evolution of the Tcholliré-Banyo shear zone (TBSZ) that showing sinistral movement. The third deformation phase (D3), is marked by strain partitioning induced by transpression and links to the evolution of the Central Cameroon shear zone (CCSZ) that displays dextral motion. D1, D2 and D3 are associated to migmatization, development and emplacement of granitic magmatism. During D2 and D3, the magmatic rocks are emplaced under the control of the two main crustal shear zones (TBSZ and CCSZ). D4 deformation is responsible for the development of faults, fracture and joints and corresponds to brittle tectonic. The main NW-SE direction of faults and fractures suggest that D4 stage shows traces of the Benue trough. On the whole, Nappe tectonic, followed by transpressive tectonic are the main tectonic type developed during the Pan-African Orogeny in Central North Cameroon.
Journal of Geosciences and Geomatics. 2018, 6(2), 41-54. DOI: 10.12691/jgg-6-2-2
Pub. Date: June 28, 2018
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by Onyeanusi Peter Obinna, Udoh Monday Udofia, Imasuen I O, Tsaku Stephen, Omodolor Hope E and Aduomahor Benedict Oghenemaro
Original Research
Detailed analyses of geological, petrophysical and seismic datasets were employed in other to determine the effect of facies change on hydrocarbon production. Static and dynamic modeling formed the terminal point for this integrated study of the X reservoir. Petrophysical properties that determine reservoir quality were measured. The average computed reservoir thickness, pay thickness, net pay thickness, net-to-gross (NTG), porosity and water saturation for the E1000X (Reservoir Name) reservoir zone was 114.4m, 55.4m, 42.6m, 74%, 21%and 25% respectively with no significant variation. The original hydrocarbon-in-place of the reservoir was also evaluated base on mean weighted averages of porosity, water saturation, and gross rock volumes and net-to-gross ratios. Fluid types was used to define the reservoir on the basis of neutron/density log signatures which may be basically water, oil and gas. Stratigraphic model was built and correlation panel generated. This in-turn was used to delineate the facies types across the interpreted X reservoir. The output from the facies using an acceptable global flow zone indicator (FZI) was used to model the permeability from the petrophysical analysis. Also static model was built where surfaces from seismic interpreted model was used to build a static model in other to generate geological parameters for the dynamic model simulation. In the dynamic model phase of this study, it was observed that wells placed in the channel dominated facies had better oil production performance followed by wells placed in the Shorface facies environment and least by wells placed in heterolitics environment. The prediction phase of the six wells within the 20 years period in the E1000X reservoirs shows that channels and Shoreface dominated facies gives better production performance over the production life of the wells.
Journal of Geosciences and Geomatics. 2018, 6(2), 35-40. DOI: 10.12691/jgg-6-2-1
Pub. Date: June 26, 2018
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