Browsing by Author "Ibitoye, T.A."

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    Geochemical Assessment of Bottom Sediments of Water Bodies at Crude Oil Exploration Station in Delta State, Nigeria.
    (Discovery Nature, 2025) Abolodje, O.D.; Ibe, K.A.; Osisanya, W.O.; Ibitoye, T.A.; Saleh, A.S.
    Understanding the occurrence, composition, and distribution patterns of aliphatic hydrocarbons (AHCs) are crucial signals for identifying the anthropogenic contributions and sources of AHCs present in the environment. Therefore, this study focused on analyzing the concentrations, distribution pattern, compositional patterns, and sources of AHCs found in crude oil and sediments collected from the Udu, Ethiope East, and Ughelli North Local Government Areas. A total of nine (09) crude oil samples and ten (10) sediment samples were obtained from the designated study area. The analysis of AHC concentrations in these identification was performed by gas chromatography with Flame Ionization Detector (GC-FID) using hexane/dichloromethane mixture and further purification in a column filled with silica gel and alumina. The AHC in the crude oil samples were observed to be between 450 and 43657 mg/kg, with an average of 2859.11+7884.68mg/kg. The sediment samples on the other hand contained concentrations of AHC that varied between 10.8 and 470mg/kg with a mean concentration of 102.74 +2.85 mg/kg. The UNEP guideline limit of AHCs in sediments is 10 mg/kg, yet they were greater than those. The AHCs of the crude in the Ethiope East Local Government Area were detected to be 3071 +53.3mg/kg. Udu Local Government Area on the other hand reported concentrations of 14999 +/-314.3 and 155027 +/-291.7mg/kg. AHCs of the Ughelli North Local Government Area were 1149±69.7, 21686±3352.8, 14099±147.7, 450±17.3, 1114±19.6, and 43657±2185.3 mg/kg. Regarding sediment, the AHCs recorded were 12.7±0.3 and 18.8±0.6 mg/kg for Ethiope East Local Government Area, while Udu Local Government Area presents recorded values of 17. The results of the ANOVA reveal a significant difference (p<0.05) in the levels of AHCs found in both crude oil and sediment samples. Furthermore, the regression analysis indicates a minimal or nonexistent correlation between AHC concentrations in crude oil and those in sediment. Notably, the predominant hydrocarbons (MH) identified in the samples of crude oil and sediment were characterized by even carbon numbers, including C8, C16, C18, C32, C34, C36, and C38.
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    Hydrocarbon Play Assessment of “Oswil” Field, Onshore Niger Delta Region.
    (The Bilingual Publishing Group, 2021-01) Osisanya, W.O.; Alile, O.M.; Eze, S.U.; Ibitoye, T.A.; Oyanameh, O.E.
    Hydrocarbon play assessment of any field involves the evaluation of the production capacity of hydrocarbon reservoir unit in the field. This involves detail study of the reservoir petrophysical properties and geological interpretation of structures suitable for hydrocarbon accumulation in the field as observed from seismic reflection images. This study details the assessment of hydrocarbon play in OSWIL field onshore in Niger Delta, with the intent of appraising its productivity using a combination of seismic, well logs, petrophysical parameters and volumetric estimation using proven tech niques which involves an integrated methodology. Two reservoir windows “R1” and “R2” were defined from five wells OSWIL-02, 04, 06, 07 and 12. The top and base of each reservoir window was delineated from the wells. Structural interpretation for inline 6975 revealed two horizons (X and Y) and eight faults labelled (F1, F2, F6, F8, F10, F16, F17 and F18). Five faults (F1, F6, F10, F17 and F18) were identified as synthetic faults and dip basin wards while three faults (F2, F8 and F16) were identified as antithetic faults and dips landwards. Time-depth structural map at top of reservoirs R1 and R2 revealed structural highs and closures. These observations are characteristics of growth structures (faults) which depicts the tectonic style of the Niger Delta. Results of petrophysical evaluation for reservoirs “R1” and “R2” across the five wells were analysed. For reservoir “R1” effective porosity values of 27%, 26%, 23%, 20% and 22% were obtained for wells OSWIL-04, 12, 07, 06 and 02 respectively with an average of 23.6%, while for reservoir “R2” effective porosity values of 26%, 22%, 21%, 24% and 23% for wells OSWIL-04, 12, 07, 06 and 02 were obtained respectively with an average of 23.2%. This porosity values correspond with the already established porosity range of 28-32% within the Agbada formation of the Niger Delta. Permeability index of the order (K > 100mD) were obtained for both reservoirs across the five wells and is rated very good. Hydrocar bon saturation (Shc) across the five wells averages at 61.6% for reservoir “R1” and 67.4% for reservoir “R2”. Result of petrophysical model for porosity, permeability and water saturation reveal that the reservoir system in R1 and R2 is fault assisted and fluid flow within both reservoirs is aided by presence of effective porosity and faulting. Volumetric estimation for both reservoirs showed that reservoir R1 contains an estimate of 455 × 106 STB of hydrocarbon in place, while reservoir R2 contains an estimate of 683 × 106 STB of hydrocarbon in place. These findings impact positively on hydrocarbon production in the field and affirm that the two reservoirs R1 and R2 are highly prospective.