The Mamuniyat petroleum reservoir in southwestern Libya is comprised of clean sandstones and intercalated shale and sand facies that are characterized by spatial porosity variations. Seismic reflection data from the field exhibit relatively low vertical seismic resolution, side lobes of reflection wavelets, reflection interference, and low acoustic impedance contrast between the reservoir and the units underneath the reservoir, which make mapping those facies a difficult task. In the absence of broadband seismic data, optimizing frequency bands of bandlimited data can be used to suppress pseudoreflectors resulting from side-lobe effects and help to separate the clean sandstone facies of the reservoir. We have optimized the data based on our investigation of seismic frequency bands and used instantaneous frequency analysis to reveal the reflection discontinuity that is mainly associated with the reservoir boundary of the sandstone facies of the clean Mamuniyat reservoir. We also preformed rock-physics diagnostic modeling and inverted the seismic data using spectral-based colored inversion into relative acoustic impedance. The inverted impedance matches the up-scaled impedance from the well data and the inversion of relative acoustic impedance confirms the conclusion that was drawn from the instantaneous frequency results. The interpretation of facies distributions based on the instantaneous frequency was supported by the inversion results and the rock-physics models.

Cambrian-Ordovician and Upper Cretaceous reservoir formations, the primary producing formations in the Sirte Basin, Libya have complex structures which affect the performance of the reservoirs. It is critical to understand the complicated relationships between fault networks, fractures, and stratigraphy of the area for future field development. However, detecting faults especially subtle faults and fractures is a challenging task using conventional seismic data due to the low signal-to-noise ratio. Seismic attributes provide effective tools in identifying and enhancing fault and fracture interpretation beyond the seismic resolution of the conventional seismic data. In this study, we focus on coherence and curvature attributes extracted from the poststack 3D seismic data acquired in the central Sirte Basin to delineate subtle fault and fracture zones. We applied a median filter and spectral whitening to enhance the data quality and remove noise resulted from acquisition and processing effects. We utilized these methods to produce high-resolution data and preserve structural features. A total of 17 faults have been identified in the study area. The most common fractures in the Cambrian-Ordovician reservoir formations are in the northwest and southeast of the field. Seismic data conditioning and seismic attribute analyses applied on the 3-D seismic data effectively increased our understanding of the reservoir complex and help detect and identify subtle faults and fracture zones in the study area.

The Cambrian-Ordovician and Upper Cretaceous formations, which are the main oil-producing formations in the central Sirte Basin, are structurally complex. The lateral and vertical heterogeneity of the reservoir formations is not well-understood, which negatively affects the performance of the reservoirs. We constructed efficient full-field static models that incorporate the lateral and vertical variation of those reservoir formations by integrating geologic and geophysical data. We determined lithology and reservoir properties by selecting appropriate petrophysical techniques that suit the available well data and overcome issues with unreliable well-log measurements. In the process of building structural models, defining and mapping the base of the Cambrian-Ordovician Gargaf Formation was very challenging because wells did not penetrate the basal formation, and the quality of the seismic data decreases with depth. Therefore, we applied techniques of adding isochore maps of the overlying Upper Cretaceous of the Bahi and Waha Formations to map basal contact and determine the thickness of the Gargaf Formation for the first time in the area. The constructed isochore maps showed the thickness variation and the distributions of the Bahi and Waha Formations and explained the influence of Gargaf paleotopography and faults on them. The fault models combined with facies and property models suggested an interconnection among the three main reservoirs. They also indicated that the quality of the Waha reservoir enhances as the lithology varies from limestones to calcareous sandstones, whereas the quality of the Gargaf reservoir was primarily controlled by fractures. The total estimate of the original oil in place with the largest contribution of hydrocarbon volume from the Waha Formation was [Formula: see text] stock tank barrel. The created model with a fine-scale geocellular covering an area of [Formula: see text] is unique to the study area and it can be updated and refined at any time with new data production and drilling activities.

Late Ordovician glacial deposits of the Mamuniyat Formation are the main oil reservoir in the Murzuq Basin in Libya. Autopicking the strong reflection at the base of the Silurian shales can be used to map the top of the Mamuniyat reservoir in the area where it is in direct contact with the Silurian shales. However, in areas where the Bir Tlacsin Formation, a mud‐prone unit, is between the Silurian shales and the Mamuniyat reservoir, the top of the Mamuniyat is difficult to pick because the units juxtaposed across the boundary are too similar to produce a strong reflection. Defining the Bir Tlacsin facies is important because it impacts hydrocarbon accumulation and migration. To predict the distribution of the shaly facies of Bir Tlacsin and enhance mapping of the top Mamuniyat reservoir, we utilized a continuous wavelet transform to identify the distinctive thickness of the Hot Shale and Bir Tlacsin units. We also used genetic inversion to distinguish the bulk density of the Bir Tlacsin facies. A 64 Hz frequency gave good time resolution to the amplitude spectrum and was used to predict the facies distribution of the Bir Tlacsin. In contrast, the 24 Hz frequency showed good frequency resolution of the amplitude spectrum and was used to estimate the temporal thickness of the non‐reservoir unit of Bir Tlacsin and Hot Shale. That estimate was then used to modify the autopick horizon for the base of the Silurian reflector to approximate the top of the Mamuniyat reservoir. Because of the large density contrast between the shaly facies of the Bir Tlacsin and the underlying and overlying units, inverted density also provides a way to predict the distribution of the Bir Tlacsin through estimated temporal thickness and to enhance mapping of the top Mamuniyat reservoir through mapping the base of the inverted density of the Bir Tlacsin. A comparison between mapping of the top reservoir using spectral decomposition and inverted density with respect to autopick shows that both methods improved the top of the Mamuniyat reservoir mapping. Prediction of the presence of Bir Tlacsin and improved accuracy of the top of the Mamuniyat reservoir mapping reduce the risk of drilling the shaly facies of Bir Tlacsin and provide a better estimate of the reservoir reserve.

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