scholarly journals Application of seismic stratigraphy and structural analysis in the determination of petroleum plays within the Eastern Niger Delta Basin, Nigeria

2015 ◽  
Vol 5 (2) ◽  
pp. 113-122 ◽  
Author(s):  
D. O. Anomneze ◽  
A. U. Okoro ◽  
N. E. Ajaegwu ◽  
E. O. Akpunonu ◽  
C. V. Ahaneku ◽  
...  
Keyword(s):  
Structural Analysis ◽  
Niger Delta ◽  
Seismic Stratigraphy ◽  
Niger Delta Basin

scholarly journals Modeling the Chance of Commerciality of Petroleum Assets for Economic Development

2021 ◽  
pp. 40-61
Author(s):  
U. Georgeson Victor ◽  
Omowumi O. Iledare ◽  
Joseph A. Ajienka
Keyword(s):  
Economic Development ◽  
Case Studies ◽  
Building Block ◽  
Niger Delta ◽  
Petroleum Resources ◽  
Niger Delta Basin ◽  
Cost Implications ◽  
The Cost ◽  
New Framework

The chance to discover hydrocarbon volumes of economic quantity diminishes with progressive discovery in explored basins. Given the preponderance of smaller deposits in extensively explored basins and the cost implications of discovering deposits less than the required Minimum Economic Reserves (MER), explorationists and investors in exploration activities need a framework to evaluate the chance of a successful petroleum resources discovery to minimize the risk of unsuccessful exploration. This study develops a new framework to evaluate the chance of discovery of at least a minimum economic reserves volume in an extensively explored basin. It leverages on the postulation for the determination of probability of hydrocarbon economic success as a building block for the new framework. The model combines the concepts of Minimum Economic Reserves, Discovery Efficiency and Probability to derive an explicit analytical function for discovery efficiency and hydrocarbon probability for a commercial discovery. It digitalizes existing Risk Table to ease the complexity to obtain geological chance of success and hydrocarbon asset evaluation for commerciality. Nine Case studies from the prolific Niger Delta basin of Nigeria are used to validate the model. The result of the semi-digital solution of the model shows that three of the studied cases are commercial whereas the remaining six cases are sub-commercial. The study recommends the application of the new framework for hydrocarbon asset evaluation for chance of commerciality to complement models like the cream off curve to predict chance of commercial discovery of hydrocarbon assets.

Seismic interpretation, structural analysis, and fractal study of the Greater Ughelli Depobelt, Niger Delta Basin, Nigeria

2011 ◽  
Vol 30 (6) ◽  
pp. 640-648 ◽  
Author(s):  
D. K. Amogu ◽  
J. Filbrandt ◽  
K. O. Ladipo ◽  
C. Anowai ◽  
K. Onuoha
Keyword(s):  
Structural Analysis ◽  
Niger Delta ◽  
Seismic Interpretation ◽  
Niger Delta Basin

scholarly journals Determination of Geothermal Gradient from Bore Hole Temperature data in Some Parts of the Eastern Niger Delta Basin

2021 ◽  
pp. 39-46
Author(s):  
E. D. Uko ◽  
M. A. Alabraba ◽  
I. Tamunoberetonari ◽  
A. O. Oki
Keyword(s):  
Niger Delta ◽  
Good Reason ◽  
Geothermal Gradient ◽  
Temperature Data ◽  
Oil Fields ◽  
Basin Evolution ◽  
Geothermal Gradients ◽  
Oil Hydrocarbons ◽  
Niger Delta Basin

An analysis of Geothermal Gradients in the Eastern Niger Delta basin was done using Bore Hole Temperature (BHT) data from three (3) adjacent oil fields. BHT data was converted to static formation temperature by using the conventional method of increasing measured BHT data by 10% and Geothermal Gradient computed using its simple linear relationship with depth, surface temperature and static temperature at depth. Projections were then made for change in Geothermal gradients at 1km intervals to a depth of 4 km. Results obtained showed significant variations across Idama, Inda and Robertkiri fields with average geothermal gradients of 17.3⁰C/Km, 22.6⁰C/Km and 23.1⁰C/Km respectively. Variation in the geothermal gradients in the area is attributed to lithological control and differential rates of sedimentation during basin evolution. Also, results showed that the Geothermal Gradient in the area are generally moderate and could be a good reason for the occurrence of more oil hydrocarbons than gas in the area.

scholarly journals THE EFFECT OF DENSITY-VELOCITY RELATION PARAMETERS ON DENSITY CURVES IN TAU (τ) FIELD, NIGER DELTA BASIN

2020 ◽  
Vol 4 (2) ◽  
pp. 54-58
Author(s):  
Atat, J. G. ◽  
Akankpo, A. O. ◽  
Umoren, E. B. ◽  
Horsfall, O. I. ◽  
Ekpo, S. S
Keyword(s):  
Density Estimation ◽  
Niger Delta ◽  
Accurate Result ◽  
Oil Field ◽  
Well Log ◽  
Velocity Relation ◽  
Density Values ◽  
Niger Delta Basin

We considered the constants obtained for tau (𝜏)Field in the Niger Delta basin from well-log data of three wells (A,B,C) to investigate the effect of inclusion of these constants on density-velocity relation using Hampson Russell Software to generate density curve in tau field. The curves were compared to those generated from Gardner and Lindseth constants and in-situ density curves. Many researchers have worked on constants for density-velocity equations for different Fields; their results always differ from Gardner and Lindseth constants including the constants of Atat et al., 2020 which are considered in this investigation as Tau Field local fit constants. Our findings support the results of these researchers. Results indicate over estimation of density curves when using Gardner and Lindseth constants. The challenge is that in-situ density curves are not accurate due to sand-shale overlap of density values. The most improved and accurate result is given by the density curves obtained using the constants for specific sand and shale lithologies (local fits). This verifies the need for the determination of constants for local fit of the oil field under investigation. The pink curves truly indicate the density estimation for the tau field which is very reliable in the characterisation of reservoir.

scholarly journals Quantitative prediction of overburden pressure and overpressure zones using well logs - a case study of an x-field in the Niger-delta basin, Nigeria

2018 ◽  
Vol 6 (1) ◽  
pp. 65
Author(s):  
Chidozie Opara ◽  
Michael Ohakwereze ◽  
Okechukwu Adizua
Keyword(s):  
Bulk Density ◽  
Niger Delta ◽  
Quantitative Prediction ◽  
Overburden Pressure ◽  
Exploration And Production ◽  
Vertical Effective Stress ◽  
Niger Delta Basin ◽  
Sonic Logs

Prediction and evaluation of overburden pressure are critical for the exploration and production of hydrocarbon reservoirs. Overburden pressure was estimated using well log (density and sonic) data obtained from two wells (B1 and B2) of an X - Field within the Niger Delta basin. Overburden pressure depends primarily on the bulk density data. Bulk density was extracted from density and sonic logs based on the log signatures. The bulk density was then used to determine overburden pressure using Eaton’s equation. The results reveal that overburden pressure increases linearly with depth, and an overburden gradient of 1.0 psi/Ft. was obtained. The overburden pressure was used to estimate pore pressure and vertical effective stress and thus enabled the determination of overpressure zones within the well.

Lithofacies Analysis and Qualitative Minerology of the Sediments of #3 Well in the Greater Ughelli Depobelt, Niger Delta Basin

2021 ◽  
Vol 13 (2) ◽  
pp. 601-610
Author(s):  
K. Itiowe ◽  
R. Oghonyon ◽  
B. K. Kurah
Keyword(s):  
Physical Properties ◽  
Clay Minerals ◽  
Niger Delta ◽  
Reservoir Quality ◽  
X Ray Diffraction ◽  
X Ray ◽  
Sandy Shale ◽  
Heterogeneous Nature ◽  
Niger Delta Basin ◽  
Shaly Sandstone

The sediment of #3 Well of the Greater Ughelli Depobelt are represented by sand and shale intercalation. In this study, lithofacies analysis and X-ray diffraction technique were used to characterize the sediments from the well. The lithofacies analysis was based on the physical properties of the sediments encountered from the ditch cuttings.  Five lithofacies types of mainly sandstone, clayey sandstone, shaly sandstone, sandy shale and shale and 53 lithofacies zones were identified from 15 ft to 11295 ft. The result of the X-ray diffraction analysis identified that the following clay minerals – kaolinite, illite/muscovite, sepiolite, chlorite, calcite, dolomite; with kaolinite in greater percentage. The non-clay minerals include quartz, pyrite, anatase, gypsum, plagioclase, microcline, jarosite, barite and fluorite; with quartz having the highest percentage. Therefore, due to the high percentage of kaolinite in #3 well, the pore filing kaolinite may have more effect on the reservoir quality than illite/muscovite, chlorite and sepiolite. By considering the physical properties, homogenous and heterogeneous nature of the #3 Well, it would be concluded that #3 Well has some prospect for petroleum and gas exploration.

Sedimentary facies and petrographic analyses of Miocene nearshore deposits, Central Swamp Depobelt, onshore Niger Delta Basin: implications for reservoir quality

2021 ◽  
Author(s):  
Joseph Nanaoweikule Eradiri ◽  
Ehimare Erhire Odafen ◽  
Ikenna Christopher Okwara ◽  
Ayonma Wilfred Mode ◽  
Okwudiri Aloysius Anyiam ◽  
...  
Keyword(s):  
Niger Delta ◽  
Sedimentary Facies ◽  
Reservoir Quality ◽  
Petrographic Analyses ◽  
Niger Delta Basin

Evaluation of Reservoir’s Petrophysical Parameters, Niger Delta, Nigeria

2017 ◽  
Vol 5 (1) ◽  
pp. 19
Author(s):  
Ubong Essien ◽  
Akaninyene Akankpo ◽  
Okechukwu Agbasi
Keyword(s):  
Niger Delta ◽  
Gamma Ray ◽  
Water Saturation ◽  
Petrophysical Parameters ◽  
Niger Delta Region ◽  
Average Porosity ◽  
Irreducible Water Saturation ◽  
Open Hole ◽  
Bulk Volume ◽  
Niger Delta Basin

Petrophysical analysis was performed in two wells in the Niger Delta Region, Nigeria. This study is aimed at making available petrophysical data, basically water saturation calculation using cementation values of 2.0 for the reservoir formations of two wells in the Niger delta basin. A suite of geophysical open hole logs namely Gamma ray; Resistivity, Sonic, Caliper and Density were used to determine petrophysical parameters. The parameters determined are; volume of shale, porosity, water saturation, irreducible water saturation and bulk volume of water. The thickness of the reservoir varies between 127ft and 1620ft. Average porosity values vary between 0.061 and 0.600; generally decreasing with depth. The mean average computed values for the Petrophysical parameters for the reservoirs are: Bulk Volume of Water, 0.070 to 0.175; Apparent Water Resistivity, 0.239 to 7.969; Water Saturation, 0.229 to 0.749; Irreducible Water Saturation, 0.229 to 0.882 and Volume of Shale, 0.045 to 0.355. The findings will also enhance the proper characterization of the reservoir sands.

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