The recent achievement in unconventional reservoirs has established the objective of reevaluating the oil-bearing tight carbonates as potential oil production reservoirs. Of these carbonates, the Turonian Abu Roash D (AR/D) tight limestone in the Abu Sennan field of the Western Desert, Egypt contains oil, but has extremely poor recovery. The challenge in this study is to define the effective parameters that control the various petrophysical attributes of this tight reservoir and their influence on reservoir recovery.

Integrated sedimentological analysis and poroperm characterization was performed based on various data sets, including conventional core analysis, mercury injection tests, and petrographic inspection. A core-calibrated image-perm software algorithm was processed to evaluate the heterogeneity of reservoir pore system and to provide a continuous and azimuthal output of high resolution porosity and permeability.

The AR/D limestone succession (approximately 82 m thick) consists almost entirely of offshore-outer ramp bioclastic wackestone-mudstone facies, with the exception of a reduced reservoir-forming interval (approximately 10 m thick), which consists of inner- to mid-ramp facies. The outer-ramp offshore facies have very poor reservoir quality, with total porosity of less than 9% and permeability values that never exceed 0.1 mD. The reservoir-forming interval begins with storm beds of whole fossil rudstone and bioclastic wackestone, and gradationally terminates upward with inner-ramp shoal beds (5 m thick) of benthic foraminiferal peloidal packstone. The shoal facies measure a noticeably enhanced porosity (15 to 27%) with a relative increase in permeability (up to 2.3 mD). However, a petrographic inspection with resistivity image analysis showed a clear paucity of visible mega- and meso-pores or significant natural open fractures. This means that the reservoir pore system is of the intercrystalline microporosity type, which is confirmed by scanning electron microscope (SEM) and the measured pore throat radii ranging between 1 and 0.005μ. The prevalence of microporosity in the best zone of AR/D reservoir is also evident by a unimodal porosity range distribution shown by an image-perm output. This homogeneous and volumetrically significant microporosity nature may provide a favorable recovery if a suitable fracturing design is applied.

This study highlights the effect of microporosity types on the permeability of tight limestone reservoir, and emphasizes the workflow and benefits of the image-perm technique in evaluating the poroperm system and heterogeneity in the porosity distribution in carbonate reservoirs.

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