Porosity and compaction trend in Okan field (Western Niger Delta) based on well log data.

Egeh, E U; Okereke, C.S.; Olagundoye, Olatunbosun

doi:10.4314/gjpas.v7i1.16211

Cited by 2 publications

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“…The values for effective porosity obtained in this work, range averagely from 22.25 to 28.32%, and are very high. These results agree with conclusions made by Selley and Morrill (1983) and Egeh et al (2001) which concluded that, almost all reservoirs have porosity in a range of 5 to 30%.…”

Section: Porosity Trendssupporting

confidence: 93%

Analysis of shaly sand reservoir rocks in the eastern Niger Delta Basin using geophysical well logs

Fozao¹,

Lordon²,

Ali³

et al. 2019

J. Petroleum Gas Eng.

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Shales in the reservoir causes complications for the petrophysicist because they generally are conductive and mask the high resistance characteristic of hydrocarbons. Data from a suite of well logs were used to estimate the effect of reservoir shaliness on petrophysical parameters of some reservoir rocks of the eastern Niger Delta Basin. The log section was digitized using Neuralog software. Delineation of the productive clean and dirty formations, as well as mapping of the fluid contents of the possible reservoir zones was carried out using Interactive Petrophysics software. Fifteen shaly sand bodies were identified. It was observed that, shale correction leads to a significant change in petrophysical parameters. The results obtained indicate that, the Simandoux and Indonesian models used for the study are both suitable for water saturation, and hydrocarbon saturation analysis in shaly sands of this part of the Basin. The porosity results for the Indonesian and Simandoux models gave, respectively 0.14-0.23 and 0.22-0.28, while the hydrocarbon saturation results are 0.650-0.908 and 0.650-0.911 with permeabilities values of 1487.442-8881.697 mD and 1568.532-7451.592 mD for uncorrected and corrected permeability, respectively. Thomas-Stieber model shows that shale distribution in sands of the eastern Niger Delta Basin is mainly structural with few of disperse and laminar ones.

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Section: Porosity Trendssupporting

confidence: 93%

Analysis of shaly sand reservoir rocks in the eastern Niger Delta Basin using geophysical well logs

Fozao¹,

Lordon²,

Ali³

et al. 2019

J. Petroleum Gas Eng.

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show abstract

“…Porosity is one of the vital qualities of any hydrocarbon basin or reservoir. Reservoirs have porosity ranging from 5% to 45%, though most of them are within 10% and 20% [2]. Porosity field is also vital as it may be used to calculate abnormal pressure areas as oil-well is drilled [3,4].…”

Section: Introductionmentioning

confidence: 99%

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2023

World J. Adv. Sci. Technol.

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The assessment of rock reservoir volume concentration is necessary as it accounts for the appreciable pore spaces available for hydrocarbon and other targets. Raw well d-ata from oil wells A, B and C in some parts of the Niger Delta Basin (XA Field) were used for porosity estimates in sandstone and shale formations. Using the Microsoft Excel for analysis, gamma ray log, density log with respect to depth were generated. The results of these curves were used to estimate porosity and create models for porosity-formation factor with respect to density effect. The major findings revealed the average porosity values as about 20% for well A, 17% for well B and 19% for well C. The results show that increase in density gives rise to a decrease in porosity in both lithologies. In order to establish a relationship between porosity of this Field rock reservoir, a plot of porosity with formation factor due to density influence was necessary. These curves lead to several equations with the average for linear curves as 𝐹 𝐷 = −400∅ 𝑋 𝐴 + 98.08 and 𝐹 𝐷 = (−0.2∅ 𝑋 𝐴 + 4.9) × 10 −3 for fractional and percentage porosities respectively. These models show that both parameters are strongly related with coefficients of 0.9723 (for both plots from well A), 0.8274 (for both plots from well B) and 0.9689 (for both plots from well C) for XA Field. These results correspond to the non-linear relation, ∅ 𝑋 𝐴 = 0.8006𝐹 𝐷 −0.465 as the original values of the cementation exponent and the tortuosity factor are obtained, if the formation factor is considered as the subject.

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Porosity and compaction trend in Okan field (Western Niger Delta) based on well log data.

Cited by 2 publications

References 0 publications

Analysis of shaly sand reservoir rocks in the eastern Niger Delta Basin using geophysical well logs

Analysis of shaly sand reservoir rocks in the eastern Niger Delta Basin using geophysical well logs

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