الفهرس 
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Abstract
This thesis deals with the reservoir characterization and rock typing evaluation of the Messenian Abu Madi Formation in South Batra Gas Field, Nile Delta-Egypt. The South Batra Field lies in one of many deeply incised valleys around the Mediterranean, which formed during the Messinian salinity crisis (MSC). This study is based on a complete subsurface dataset from El-Mansoura concession, mainly from the South Batra (SB) Field. Available subsurface data comprise high-resolution 2D and 3D seismic, geophysical well logs and cores. Core dataset includes a cumulative 165 m conventional core intervals from SB-4 and SB-14 wells as well as side-wall cores from SB-2 well. Conventional cores cover the entire thickness of the Abu Madi level III and the lowermost part of the overlying Abu Madi level II, whereas Abu Madi level I is only represented by some scattered sidewall core samples. Conventional cores were examined to identify the lithofacies and their associated sedimentary structures that were used in combination with the corresponding gamma ray log motifs to interpret the depositional setting of the studied Abu Madi intervals. This was correlated with the extracted seismic attributes in order to identify the sedimentary facies distribution and architecture. Extracted root-mean square (RMS) seismic amplitude maps of the top Abu Madi level II and III reflections in association with their structure contour maps illustrate lenticular high-amplitude bodies that are distributed within the BES paleo-relief channels. High-amplitude facies of Abu Madi level II are restricted to the eastern channel, and pinch-out laterally westwards. The SW-NE stratigraphic correlation panel, highlights the dominant muddy composition of Abu Madi level I. Sand-rich sediments of level III are typically confined to the western and eastern channels, whereas the central channel contains clay-rich sandstones with common shale interbeds. Level II channel-fill sands are restricted to the eastern channel and pinch-out westward in an agreement with the seismic RMS-amplitude map. The Messinian incised-valley fill (IVF) sediments of the Abu Madi Formation host the most prolific gas-bearing sandstones in the onshore Nile Delta, Egypt. This study provides the first integrated geological, geophysical and petrophysical approach in order to link the Abu Madi sandstones’ reservoir properties with their geological framework, and thereby optimize the predictability of the most prospective reservoir rock types (RRT). Sandstone-bearing reservoir levels are mostly associated with the fluvial-estuarine valley-fill sediments (Abu Madi levels II and III). The intergranular volume of some sandstones (e.g. arkoses) is occupied by compacted ductile argillaceous rock fragments (pseudomatrix), and therefore have dominantly microporosity with anisotropic, poorly-connected pore system. Three RRT were recognized in Abu Madi reservoir levels. RRTI has the best poro-perm characteristics with excellent capillary properties (e.g. megapores, lowest initial displacement pressure ~10 psi air/mercury and irreducible water saturation Swir below 20%). Pore system heterogeneity increases in RRTII and RRTIII. The latter contains dominant micropores and exhibits the highest initial displacement pressure ~500 psi air/mercury and Swir exceeding 50%. RRTI often comprises subarkoses associated with the cross-bedded, massive and crosslaminated lithofacies of the fluvial channel-fill and fluvial channel sand bars facies. Whilst RRTII and III mainly comprise the sandstone lithofacies deposited in the abandoned fluvial, estuarine and restricted marine successions. Excellent reservoir quality facies follows the depositional trend of the valley-fill fluvial channels and pinches-out where repeated avulsion and channel abandonment processes dominate. The spatial distribution of Abu Madi RRT highlights the paramount impact of syn-depositional attributes and canyon-floor relief on the sediments’ reservoir heterogeneity and productivity. Moreover, the present integrated RRT approach could serve as a model for exploration in analogues settings where autogenic processes induce widespread sedimentary heterogeneity, which largely impacts the reservoir quality.