Statistical and 3D Petrophysical Analysis of Reservoir Formations and Net Pay Thickness of the Mamuniyat Formation, Sharara B-Oil Field, Murzuq Basin, Libya

Abstract

Problem Statement and Purpose. This study presents a comprehensive statistical analysis and three-dimensional (3D) petrophysical modeling of the Mamuniyat Formation in the Sharara B-Oil Field, Murzuq Basin, Libya. The primary objective is to evaluate reservoir quality and spatial heterogeneity by integrating well-log data with geostatistical simulations using industrystandard petrophysical methods. Through rigorous characterization of effective porosity and fluid saturation distributions, combined with strict net pay cutoff enforcement (Φe ≥ 10%, Vsh ≤ 30%, Sw ≤ 60%), the research identifies the most promising hydrocarbon-bearing zones and establishes a reproducible framework for reservoir evaluation in data-limited settings.

Data and Methods. An integrated statistical and 3D petrophysical characterization was performed based on quantitative analysis of wireline log data from nine wells (B01, B03, B05, B10, B12, B13, B15, B19, B29). Key methodological improvements include effective porosity derived from density logs with shale correction (Φe = Φt × [1−Vsh]) and water saturation calculated using Murzuq Basin-calibrated Archie parameters (Rw = 0.08 Ω·m at 70°C). For wells lacking legacy saturation curves, values were deterministically reconstructed to ensure dataset completeness. Petrophysical properties were spatially distributed using Sequential Gaussian Simulation within a structurally constrained 3D framework, with model accuracy confirmed by blind-well validation. Hydrocarbon Potential Score (HPS). The HPS is a composite multi-criteria index on a 0 to 1 scale, designed for objective reservoir ranking by integrating normalized petrophysical parameters weighted as follows: effective porosity (40%), water saturation (25%), shale volume (15%), total porosity (15%), and net pay thickness (5%). Unfavorable parameters were inverted during normalization to ensure higher scores consistently reflect superior reservoir quality. The HPS was calibrated against volumetric hydrocarbon indicators (net pay thickness × oil saturation) to align quality assessments with actual hydrocarbon column heights.

Results and Discussion. Results reveal pronounced vertical compartmentalization within the Mamuniyat Formation. The Upper Mamuniyat is identified as the primary reservoir target, exhibiting superior fluid properties (average Sw = 31.0%, So = 69.0%), consistent net pay distribution across the field (average thickness 7.1 meters), and the highest HPS score (0.81). The Lower Mamuniyat serves as a secondary target with highly localized commercial potential; its field-wide average net pay thickness is limited to 2.1 meters and confined to structurally elevated zones in the B15 and B29 blocks where hydrocarbon column preservation occurs. Seven wells display minimal Lower Mamuniyat net pay due to proximity to the regional oil-water contact (Sw = 64–75%). The Middle Mamuniyat is consistently non-commercial (average Sw = 82.0%, Φe = 9.2%) and functions as a vertical flow barrier. Corrected volumetric analysis confirms that the Upper Mamuniyat contributes approximately 6.9 times more hydrocarbon volume per well than the Lower Mamuniyat (hydrocarbon column: 4.90 meters versus 0.71 meters), establishing it as the optimal development target.