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Afifi A.S.,BP Egypt | Moustafa A.R.,Ain Shams University | Helmy H.M.,40 El Akshed St
Marine and Petroleum Geology | Year: 2016

A dataset in the southern Suez rift including 400 km2 of 3D depth-migrated seismic data, thirty six boreholes with geological information and outcrop data from several exposures, was examined and interpreted in order to understand the controls on the erosion of the pre-rift reservoirs at the updip edges of tilted fault blocks and its impact on hydrocarbon exploration. Surface and subsurface mapping demonstrated the existence of five regional major tilted fault blocks bounded by major down to the northeast, rift-parallel normal faults. These blocks are characterized by steep stratal dip (30-40°) and their bounding faults are dipping at 20-30° toward the NE. The major faults in the area have been subdivided into three phases based on their age. The first-phase faults were formed at the early rift opening phase and were contemporaneous with the deposition of the lowermost syn-rift unit (Nukhul Formation). The second-phase faults are contemporaneous with deposition of the Rudeis Formation (main syn-rift unit) while the third-phase faults are the youngest. Detailed study indicates that the first-phase faults controlled the rotation of the tilted fault blocks and played a major role in the erosion of the pre-rift reservoirs and top seal units at the updip edges of these blocks. The lowermost syn-rift unit (Nukhul Formation) was deposited in the downdip areas of the tilted faults blocks and did not cover the updip eroded areas. A proposed model to demonstrate the risk of drilling the crests of tilted fault blocks close to the main block-bounding faults is described in this paper and can be applied in other highly extended rift basins. © 2016 Elsevier Ltd. Source

Kortam M.,Petrobel | Anwar M.,Petrobel | Mousa D.,Petrobel | Fouad A.,Petrobel | And 4 more authors.
SPE - European Formation Damage Conference, Proceedings, EFDC | Year: 2015

The Abu Rudies field in the Egyptian Sinai peninsula produces mainly from the South Gharib formation that is characterized as a complex, heterogeneous, thick and laminated, but permeable, slightly oil wet rock and depleted sandstones consisting of sands with an average permeability in the range of 150-550 mD and Young's Modulus in the order of 1.0 - 2.5 million psi. Conventional hydraulic fracturing and Frac & Pack techniques have been traditionally deployed to produce hydrocarbons and for sand control. The added complication is the reduction in the effective permeability to oil due to the rock being oil wet. Conventional fracturing techniques have had limited success especially in the highly permeable compartments of the field due to premature screenouts that were encountered extensively, residual polymer in the intergranular porous rock and the flowback of formation sand and proppant. This paper describes the application and production enhancement efforts for the first time with a novel channel-fracturing technique combined with rod-shaped proppant in selected production targets in the Abu Rudies field in Egypt. The channel fracturing technique introduces channels within the proppant pack that significantly increase conductivity and effective fracture half-length leading to increased productivity. Rod-shaped proppant when used as tail-in in fracturing treatments increases near-wellbore fracture conductivity and completely prevents proppant/formation sands flowback as demonstrated by zero flowback due to its particular geometry. This paper describes actual case studies of fracturing a high-permeability layered reservoir using the channel fracturing technique, the problems encountered due to high leak off, low closure pressures, reservoir heterogeneity and the complexity due to adjacent water bearing layers. Finally, we demonstrate the well performance with the channel fracturing technique compared with alternate techniques. Copyright 2015, Society of Petroleum Engineers. Source

Tingay M.,University of Adelaide | Bentham P.,BP Egypt | De Feyter A.,International Egypt Oil Company | Kellner A.,RWE Dea Egypt
Geological Society Special Publication | Year: 2012

This study examines present-day stress orientations from borehole breakout and drilling-induced fractures in 57 boreholes in the Nile Delta. A total of 588 breakouts and 68 drilling-induced fractures from 50 wells reveal sharply contrasting present-day maximum horizontal stress (SHmax) orientations across the Nile Delta. A typical deltaic margin-parallel SHmax exists in parts of the Nile Delta that are below or absent from evaporites (NNE-SSW in the west, east- west in the central Nile, ESE-WNWin the east). However, a largely margin-normal (NNE-SSW) SHmax is observed in sequences underlain by evaporites in the eastern Nile Delta. The marginnormal supra-salt SHmax orientations are often subperpendicular to the strike of nearby active extensional faults, rather than being parallel to the faults as predicted by Andersonian criteria. The high angle between SHmax and strike of these extensional faults represents a new type of non-Andersonian faulting that is even less-suitably oriented for shear failure than previously described anomalous faulting such as low-angle normal faults and highly oblique strike-slip faults (e.g. San Andreas). While the mechanics of these non-Andersonian faults remains uncertain, it is suggested that the margin-normal supra-salt orientation generated by basal forces imparted upon rafted blocks sliding down seawards-dipping evaporites. © The Geological Society of London 2012. Source

Hill A.W.,British Petroleum | Arogunmati A.,British Petroleum | Wood G.A.,British Petroleum | Attoe D.,BP Egypt | And 11 more authors.
Leading Edge | Year: 2015

Experiences are described in delivering high-resolution 3D (HR3D) volumes to support the definition of drilling hazards for exploration and development drilling in different geologic settings around the world using differing levels of acquisition and processing intensity. The robustness of the HR3D approach delivers high-resolution volumetric imaging for the study of potential drilling hazards. Through acquisition trials and processing simulations, starting with a single-streamer, single-source approach to acquisition of HR3D, data can be delivered at equivalent effort to standard HR2D approaches but as a volume that allows all the advantages of 3D spatial analysis to be applied. Increasing the acquisition intensity increases the quality of the final processed volume and allows more advanced analysis approaches to be applied to the data. Use of multistreamer and multisource approaches ofers the opportunity to improve acquisition efficiency with careful consideration of spread designs to maintain high frequencies without introducing directivity effects into the final data. In cases in which there is a need for HR data to support drillinghazard or development studies, there is now no reason to not always acquire HR3D data. Similarly, in the processing of HR3D data, the full power of modern processing approaches, up to and including prestack depth migration, can be applied to provide further improvements in imaging in complex geologic settings to the benefit of drilling-hazard identification and ongoing improvements to drilling safety and operational integrity. Source

Morris E.A.,University of Liverpool | Morris E.A.,Badley Ashton America Inc. | Hodgson D.M.,University of Leeds | Flint S.S.,University of Manchester | And 3 more authors.
Journal of Sedimentary Research | Year: 2014

Frontal lobes develop during discrete periods of progradation in deep-water systems, and commonly form on the lower slope to base of slope. In reflection seismic datasets, they are identified as high-amplitude reflectors that are cut as the feeder channel lengthens. Here, an exhumed sand-prone succession (> 80% sandstone) from Sub-unit C3 of the Permian Fort Brown Formation, Laingsburg depocenter, Karoo Basin, South Africa, is interpreted as a frontal-lobe complex, constrained by its sedimentology, geometry, and stratigraphic context. Sub-unit C3 crops out as a series of sand-prone wedges. Individual beds can be followed for up to 700 m as they thin, fine, and downlap onto the underlying mudstone. The downlap pattern, absence of major erosion surfaces or truncation, and constant thickness of underlying units indicates that the wedges are non-erosional depositional bodies. Their low aspect ratio and mounded geometry contrasts markedly with architecture of terminal lobes on the basin floor. Furthermore their sedimentology is dominated by decimeter-scale sinusoidal stoss-side preserved bedforms with a range of low-angle to high-angle climbing-ripple laminated fine-grained sandstones. This indicates that the flows deposited their load rapidly close to, and downstream from, an abrupt decrease in confinement. The sedimentology, stratigraphy, crosssectional geometry, and weakly confined setting of a sand-prone system from the Giza Field, Nile Delta, is considered a close subsurface analogue, and their shared characteristics are used to establish diagnostic criteria for the identification and prediction of frontal-lobe deposits. In addition, deposits with similar facies characteristics have been found at the bases of large external levee deposits in the Fort Brown Formation (Unit D). This could support models in which frontal lobes form an initial depositional template above which external levees build, which provides further insight into the initiation and evolution of submarine channels. Copyright © 2014, SEPM (Society for Sedimentary Geology). Source

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