Abstract
This paper presents the study of the heterogeneity in lithofacies, porosity, permeability, mineral grain density, pore-throats sizes and hydraulic rock types and the intra sand-body compartmentalization in cored delta-front deposit of Greater Ughelli depobelt of Niger Delta. Sedimentological study of core samples results in the identification of nine lithofacies and the interpretation of environments of deposition as mainly proximal and distal delta-front mouth bar. The sand unit indicates moderate to excellent reservoir quality with core porosity between 16.2 and 29.5% and permeability between 16.8 and 7,560 md. Dykstra-Parsons core permeability distribution coefficient of 0.97 indicates that the studied reservoir sand-body is vertically highly heterogeneous, with high potential for vertical intra sand-body compartmentalization. Graphical cluster analysis of Flow Zone Indicators (FZI) led to the identification of nine Hydraulic Flow Units (HFU) with distribution controlled by depositional facies. The prediction of permeability, porethroats (r35) and flow zone indicator values of the reservoir in an uncored-well using predictive mathematical models developed with multiple regression analysis enabled the inter-well correlation of hydraulic flow units and indicates lateral continuity of reservoir compartments. An intra sand-body compartmentalization evaluated with core permeability values, Winland r35 coefficients and flow zone indicators was corroborated with formation pressure data analysis. Results show that the studied delta front-mouth bar reservoir is vertically compartmentalized by intercalated shales. Fractures in over-pressured zones were found to reduce vertical reservoir fluid compartmentalization by intercalated shales. However, reduction in reservoir pressure due to hydrocarbon production can result in dynamic compartmentalization and consequently, reduction in hydrocarbon recovery.
Highlights
Water breakthrough, dry holes and early field abandonment are serious challenging situations in the exploration and production of hydrocarbon
The average core porosity and permeability values of 20.5% and 2,172 md respectively, as well as the intervals with core porosity (22.5-29.5%) and core permeability (7560-27320 md) values anomalously higher than the stated average values and the dominance of mesoporous to megaporous rock types (>10.0 μm) from semilog plot classification of Winland r35 values indicate that the studied sand-body forms very good to excellent reservoir quality (Svirsky et al, 2004; Dresser, 1982)
Core sample description and petrophysical data interpretations show that the studied delta front-mouth bar reservoir is highly heterogeneous
Summary
Dry holes and early field abandonment are serious challenging situations in the exploration and production of hydrocarbon. Proper identification and knowledge of various scales of reservoir heterogeneities is necessary because different scale of heterogeneities have different impact on reservoir performance, production forecasts and hydrocarbon recovery (Singh et al, 2013).
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