--> ABSTRACT: Distribution Patterns of Porosity and Permeability in the Reservoir Sands of the Agbada Formation, Niger Delta, by Chiamogu, George A.; Ehinola, Olugbenga ; #90142 (2012)

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Distribution Patterns of Porosity and Permeability in the Reservoir Sands of the Agbada Formation, Niger Delta

Chiamogu, George A.*1; Ehinola, Olugbenga 2
(1) Subsurface Consultants Limited, Lagos, Lagos, Nigeria.
(2) Dept of Geology, University of Ibadan, Ibadan, Nigeria.

The Agbada Formation forms the most prolific hydrocarbon- producing interval in the Niger delta. Considerable volumes of oil are thought to have been by-passed due to incomplete understanding of reservoir quality distributions in fields and prospects, and above all the assumption that porosity (θ) and permeability (κ) could be too low to sustain economic production at depths below present investigation(>12000ft). This study examines the characteristics, variability and distribution patterns of porosity and permeability and developed predictive models for quick assessment of exploration and development opportunities for the region. An understanding of the distribution of these properties is necessary for well placement strategies. 400 core measurements of θ and κ data from 19 oil and gas wells were utilized.Statistical and regression/trend analysis of the core measurements based on depobelts classification of the dataset were run with the aid of MS Excel and Scientific Package for Social Sciences(SPSS).The results of the analyses show that a wide range of θ and κ values characterize the reservoir rocks.Mean θ and κ of 21.92% and 1005.81mD; 25.26 % and 2007.27 mD, 25.04 % and 851.73 mD, 25.95% and 1874.34 mD were established for the Offshore, Coastal Swamp, Central Swamp and Greater Ughelli depobelts respectively. While Permeability is highly variable and showed no marked relationship with depth nor any clear trend within and across depobelts,decrease of porosity with increasing burial depth is gradual , not episodic, at a rate of 2% every 1000 ft at the shallower level (<5000 ft) lowering to 1-1.5% at greater depths (>12,000 ft). For a composite sandstone sequence representing a wide range of depositional environment and subsequent diagenetic histories, all regression models (Linear, power-law, logarithmic, and exponential) predict θ reasonably well at intermediate to deeper depths. At surface of deposition to depths of about 5000 ft, linear model is the only viable predictive model. Again, all depobelts exhibit different porosity- permeability relationships, attributable to variations in deposition and diagenesis. 44% is proposed as the initial θ and 16,000 ft as a limit for encountering good reservoir quality sandstones,if a 10% porosity cut-off is assumed for resource evaluation.

 

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California