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.
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.
Tingay M.,Curtin University Australia |
Tingay M.,University of Adelaide |
Bentham P.,BP Egypt |
de Feyter A.,International Egypt Oil Company |
Kellner A.,RWE Dea Egypt
Bulletin of the Geological Society of America | Year: 2011
Evaporitic horizons are routinely interpreted to act as mechanical detachment sequences and thus significantly influence the structural evolution of sedimentary basins and fold-thrust belts. However, over 30 years of global in situ stress analysis have provided only poor evidence to support this widespread assumption. This study examines present-day stress orientations inferred from borehole breakout and drilling-induced fractures in 44 boreholes in the offshore Nile Delta. A total of 446 breakouts and 19 drilling-induced fractures from 37 wells reveal sharply contrasting present-day maximum horizontal stress (SHmax) orientations in sequences above and below the extensive Messinian evaporites of the eastern Nile Delta. A typical deltaic margin-parallel SHmax (E-W in the central and ESE-WNW in the eastern Nile Delta) is observed in parts of the Nile Delta that are below or do not contain evaporites. However, a scattered but largely margin-normal (NNE-SSW) SHmax is observed in sequences underlain by evaporites. The ~90° variation in present-day SHmax orientation above and below the Messinian salts provides the first convincing in situ evidence that evaporite sequences can act as major mechanical detachment horizons. In addition, the margin-normal SHmax orientation is subperpendicular to the strike of nearby active extensional faults, indicating the existence of non-Andersonian faulting in the suprasalt region. Furthermore, the evidence that the Messinian evaporites act as an effective mechanical detachment suggests that suprasalt faulting in the eastern Nile Delta is not the result of basement-related deformation and thus raises doubts about the often postulated extension of the Suez fault zone into the eastern Mediterranean. © 2011 Geological Society of America.
Shamma H.L.,BP Egypt |
Nelson R.,BP Egypt |
Vazquez M.L.,Schlumberger |
Shah S.H.,Schlumberger |
And 2 more authors.
Society of Petroleum Engineers - North Africa Technical Conference and Exhibition 2013, NATC 2013 | Year: 2013
Well A, encountered multiple depleted reservoir layers (initial reservoir pressure >10840 psi) with up to 5,000 psi differential pressure across layers due to irregular depletion in thin bedded shale and sand layers. Well was drilled with over 16 ppg mud to limit under balance in any higher pressure layer and overbalance in depleted layers. After drilling 4 lopes of sand body and during the start of drilling the last sand lope, complete loss of circulation was encountered, followed by kick and differential sticking. The original well integrity assurance plan considered the deployment of borehole compensated sonic tool in order to acquire a discriminated cement bond log based on attenuation measurement. Also in the plan, a Cased Hole Dynamic Tester tool was to be run and the selection of pressure points to be based on the results of the cbl-vdl. So to assure the full integrity of the cement and be able to conduct the Cased Hole Dynamic Tester as required and proper decision to be evaluated regarding the Type of GP job, the use of the Ultrasonic Imaging Tool was evaluated to be run under tough and challenging conditions (high mud weight and thick wall thickness). The Ultrasonic tool for cement to casing bond evaluation is typically limited by the attenuation of the ultrasonic echo caused by the wellbore mud weight and composition. With the cooperation between BP PhPc and Schlumberger, and making use of worldwide expertise, the decision was taken to include the Ultrasonic Tool in the cement evaluation suite despite the well conditions. The analysis of the log managed to prove the zonal isolation requirements and be a source of development of best practices that can improve cement evaluation even with the presence of heavy SOBM. Copyright 2013, Society of Petroleum Engineers.
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).
El Gazzar A.M.,BP Egypt |
Moustafa A.R.,Ain Shams University |
Bentham P.,BP Egypt
Journal of African Earth Sciences | Year: 2016
Discovered in 1969, the Abu Gharadig (AG) Field was the first large hydrocarbon discovery in the Abu Gharadig Basin of the Western Desert of Egypt. Oil production began in 1973, with gas brought into production in 1975. The field produces mainly from upper Cretaceous clastic reservoirs. The AG Basin is an E-W trending intracratonic rift basin, about 330 km long and 50–75 km wide. It was initially formed as a large half graben basin during the Jurassic time in response to Tethyan rifting and continued to subside throughout the Cretaceous time. The half graben was subsequently inverted during the Late Cretaceous as part of the Syrian Arc deformation which affected northern Egypt. The Mid-Basin Arch, the AG Anticline, and the Mubarak High are three NE-SW oriented main inversion anticlines located within the AG Basin and are controlled by inversion of pre-existing Jurassic rift faults. The AG Anticline has an overall NE-SW orientation with a gentle plunge towards the NE and SW. It is locally bounded by two NE–SW-trending inverted faults on the southwest and northeast, accounting for the asymmetry of the anticline. Reverse offset of Cretaceous horizons is obvious at these inverted faults. Fault propagation folding is developed above the tips of the inverted faults at the Late Cretaceous Abu Roash and Khoman Formations. Based on thickness changes and stratigraphic relationships, inversion started during the Santonian time and continued into the Campanian-Maastrichtian. Inversion continued during deposition of the Paleocene–Middle Eocene Apollonia Formation and the Late Eocene–Oligocene Dabaa Formation. © 2016 Elsevier Ltd
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.
Hussien M.S.M.,BP Egypt
North Africa Technical Conference and Exhibition 2010, NATC 2010 - Energy Management in a Challenging Economy | Year: 2010
This paper shows practical example in the direction of building "holistic regional depletion plan" by applying "fully holistic" and "fully probabilistic" modeling at the cost of the classic "precision" modeling that tends to include more physics. The approach came as a result of the oil industry low return on investment (ROI) that averaged at 7%. Deterministic methods usually ignore the full uncertainties distribution, associated risks, the diversification effects, and the interdependences among the chosen assets. In addition it loses the proper interaction between the technical and the commercial value drivers. As a result, many rated oil companies fall since 1990 until near future. To achieve more realistic results, decision and risk analysis (D&RA) approach together with a "holistic strategy" (based on the Nobel-Pnze wining portfolio theory that has shaped the financial markets over the past four decades and recently introduced to E&P) are applied instead of the conventional deterministic method and the "hole-istic strategy" that may lead to suboptimal solutions. Assets in the Nile Delta of Egypt were chosen to apply more modern modeling techniques by using less model "precision" for more comprehensive modeling of uncertainties and more integrated technical and business modeling. Full probabilistic methods that closely integrate technical and commercial data and tie that to the decision-making process are used to preserve more relevant information. This allowed the pertinent uncertainties to be exploited better and risks to be quantified when compared to the traditional deterministic methods. Optimization was carried out within the whole "value chain" at different "hierarchical levels" instead of optimizing parts separately that may destroy the whole value chain. With the current volatile oil market and the 2008 international financial crisis, integrating the endogenous factors (local uncertainties such as geology) and the exogenous factors (global uncertainties such as geo-economics) reduces the risk of the volatile oil pnces and the political events. Proper risk evaluation and quantification for many assets enables to build reasonable efficient frontier (EF) that a firm can use to decide its optimum situation depending on the firm willing and to avoid misallocation of capitals. Copyright 2009, Society of Petroleum Engineers.
Kabir N.,British Petroleum |
Lee K.-J.,British Petroleum |
Rietveld W.,BP Egypt |
Barley B.,BP Egypt |
And 2 more authors.
Leading Edge (Tulsa, OK) | Year: 2010
In this paper, we present a recently completed, extensive finite-difference (FD) modeling study over the West Nile Delta area in Egypt. The primary objective was to analyze the impact of various acquisition geometries on the pre-Messinian image quality. We used an innovative methodology for building the velocity and density models representative of the complexity of the offshore Nile Delta. Synthetic data showed many of the challenging features observed on field data. This allowed us to meaningfully quantify the impact of various acquisition geometries on image quality. We found that a surprisingly determinant factor influencing the final image quality is the offset distribution of the contributing traces. As offset distributions can be adjusted after the fact by applying a suitable offset-dependent weighting to recorded data, we find that by making careful use of offset weighting we can reap some of the same benefits of more complex acquisition schemes with simpler acquisition design. © 2010 Society of Exploration Geophysicists.
Souque C.,Rock Deformation Research |
Fisher Q.J.,University of Leeds |
Casey M.,University of Leeds |
Bentham P.,BP Egypt
Marine and Petroleum Geology | Year: 2010
Mechanical compaction of sand-rich reservoirs usually occurs during shallow burial and involves the rearrangement of framework grains and the ductile deformation of soft lithoclasts. The reservoir quality (porosity and permeability) of some Neogene sandstones of the South Caspian Basin has, however, been dramatically reduced by mechanical compaction involving extensive grain-fracturing (i.e. porosity collapse). These sandstones were probably susceptible to pervasive grain-fracturing because they were buried rapidly and experienced compressional deformation prior to reaching 80 °C. Consequently, they did not undergo quartz cementation and were therefore exposed to high stresses while they were extremely weak. Grain-size and structural position are also important controls on the distribution of grain fracturing in the onshore analogue in the Apsheron Peninsula. Microstructural analysis confirms that susceptibility to distributed grain-fracturing increases with increasing grain-size. Structural position has also an important impact on the distribution of porosity collapse. In particular, sandstones within the hinges of folded sections have undergone much more extensive grain-fracturing than within the surrounding area; the increased stresses in this structural position have enhanced distributed grain-fracturing and subsequent deformation band development. © 2010 Elsevier Ltd.