The deepwater area of the Nile Delta is within the eastern Mediterranean basin on the Nile Delta Cone between the Herodotus abyssal plain to the west and the Levant basin to the east. The complex evolution and interaction of the African, Eurasian and Arabian plates have shaped the Late Miocene to Recent Nile Cone and its substratum. The tectono-stratigraphic framework is controlled by deep-seated basement structures with distinct gravity and magnetic expressions, and by the interaction of the NW-trending Misfaq-Bardawil (Temsah) and NE-trending Qattara-Eratosthenes (Rosetta) fault zones. In addition, significant salt-induced deformation of a Messinian evaporitic sequence up to 4,000 m thick has occurred, together with large-scale rotational block movement. The deformational pattern is largely the result of multiphase tectonic movements along pre-existing basement faults on the continental margin of the Neo-Tethys ocean.
The Nile Cone consists of late Paleogene to Late Miocene sediments that pre-date the Messinian evaporites, and Pliocene-Pleistocene sequences. In the east, the pre-salt deposits (as much as 3,000 m thick) are primarily deepwater sediments with local condensed sequences over syndepositional intrabasinal highs. Shale occurs westward across the Rosetta trend. The Messinian evaporitic sequence exhibits three distinct seismic facies suggesting cyclic deposition with the occurrence of interbedded anhydrite, salt and clastic sequences and pure halite deposition. During the Messinian salinity crisis, large-scale canyons were excavated that resulted in multiphase cut-and-fill clastic systems. The Pliocene-Pleistocene sequences were deposited in a slope to basin-floor setting.
Exploration targets are the Pliocene-Pleistocene deepwater channel and basin-floor turbidite sands in a variety of structural settings. Water depths range from 800 to 2,800 m. The Upper Miocene sequence offers additional exploration objectives in the form of fluvial and/or turbidite sands. The focus of pre-salt exploration is the delineation of distal turbidities within the Serravallian to Tortonian sequence and the identification of new reservoir sequences deposited on pre-existing intrabasinal highs. Hydrocarbon charge has yet to be proven by drilling, but seismic amplitude anomalies and the occurrence of natural surface slicks suggest both gas and liquid charges from pre-salt source rocks through faults and salt-withdrawal windows.
The NE Mediterranean Deepwater Block (NEMED) of 41,500 sq km (Figure 1) was awarded to Shell Egypt (100%) in July 1998. The pre-effective letter was signed on November 25, 1998 allowing operations to start on February 1, 1999 with the acquisition of a 7,000 km, 2-D (6 km cable, 8 seconds, 120 fold) seismic survey. Key pre-1999 data were 1,500 km of 2-D seismic acquired by the Egyptian General Petroleum Corporation in 1973. In December 1999, Exxon Exploration and Production Egypt Limited obtained a 25 percent interest in the concession. Current exploration activity includes the acquisition of a 7,000 sq km area of 3-D seismic aimed at the identification of exploration targets. The evaluation challenge of the initial 2-D campaign was to identify the main plays and the target area of the 3-D survey by integrating seismic with new gravity and aeromagnetic data.
The Block is exceptional for its size and its location in front of a major productive delta. The newly acquired 2-D seismic data has enabled mapping of the geology of the whole concession for the first time and shows that it contains four distinct geological domains, each with unique play characteristics. Of these, only the Nile Delta gas/condensate Pliocene and Miocene Platform domain has been tested. No wells have been drilled in the Deepwater Block, but direct hydrocarbon indicators on seismic attest to a high probability of charge. The nearest wells are in the Scarab and Saffron gas fields to the south in the West Delta Deep Marine concession (Figure 2). Shallow boreholes of the Deep-Sea Drilling Project (DSDP) Leg 160 provide data in the area of the Erastothenes Seamount and to the west of Cyprus (Figure 2).
During seismic acquisition, approximately 10,000 km of onboard gravity data was acquired and fully integrated with the available satellite gravity data. In addition, some 30,750 line-km of high-resolution aeromagnetic data is available. In the central and eastern part of the block, the line spacing is 2 x 10 km, increasing in the west and northwestern areas to 4 x 20 km. Special studies focused on quantitative seismic interpretation (development of the rock property database, amplitude versus offset, and other hydrocarbon indicator studies) integrated seismic and potential field-data analysis, surface slick analysis and basin modeling.
Thirty-five years of exploration activity in the Nile Delta has led to the discovery of about 3.8 billion barrels oil equivalent (BOE), primarily gas and condensate (Figure 2). The newly acquired 2-D seismic data have substantially upgraded the prospectivity of the Block’s ultra-deepwater area. Based on the results of the 2-D seismic data, 7,000 sq km of 3-D data was acquired. The survey covers the prospective parts of the Platform, Diapir Salt and Rotated Fault Block play areas in water depths of less than 2,000 m.
TECTONIC FRAMEWORK AND STRUCTURAL SETTING
Plate Tectonic Framework
The Northeast Mediterranean Sea Deepwater Block is situated near to the northern margin of the African Plate. The plate is being actively subducted (presumably since the Late Cretaceous) along the destructive, compressional plate boundary south of Crete and Cyprus (Strabo-Pliny/Cyprus trenches; Figure 3). Seismic refraction and potential-field data (magnetic and gravity) do not yet allow a firm statement on the nature of the crust underlying the Pliocene-Pleistocene Nile Cone. What appear to be present are a thinned crust and an elevated crust/mantle boundary at a depth of 18 to 20 km. This contrasts with the Egyptian mainland and the Eratosthenes Seamount (Figures 1 and 3), where refraction and potential-field data indicate a complete upper and lower continental crust 30 to 40 km thick (Figure 4).
Various authors (Morelli, 1978; Biju-Duval et al., 1979; Dixon et al., 1984; Geiss, 1987; and Hirsch et al., 1995) envisage the presence of an oceanic crust, the maximum age of which, however, is disputed and not constrained by direct observations. If oceanic crust is present, it could be as old as the late Paleozoic/Early Triassic or as young as the Late Cretaceous. The maximum age of sediments underlying the Pliocene Nile Cone (and the occurrence of the oldest possible source-rock sequences) would logically be younger than the age of creation of the oceanic crust.
The present investigation indicates the presence of a very thick sedimentary sequence beneath the Upper Miocene salt section and of sediments older than Late Cretaceous. Even pre-Cretaceous sedimentary rocks cannot be excluded.
The structural pattern of the study area is the result of a complex interplay between three major fault trends (Figure 3):
The tectonic framework and structural setting of the study area indicates the presence of five main structural domains (Figure 5) separated by strands of the three major fault trends. The domains are Platform; Rotated Fault Blocks; Basin Floor; Diapiric Salt Basin; and Inverted Salt Basin.
The fault trends are parallel to the circum-Mediterranean plate boundaries, and seem to be old, inherited basement faults that have been periodically reactivated throughout the development of the area. The Temsah and Rosetta oblique-slip faults intersect in the southern part of the Block to create a faulted, regional high. The Platform area to the west of this high is an extension of the relatively unstructured Nile Delta Province to the south.
The Rosetta trend shows large-scale structural relief created by transpressional movement (Figure 6a). Fault movement is of Late Cretaceous age, as indicated by the onlap of the source-rock-prone Late Cretaceous and early Tertiary deepwater sediments. By Late Miocene times, the structural high was covered by basinal sediments. DSDP data from the Eratosthenes high indicates that Upper Miocene shallow-marine carbonates may be present in atoll-like features together with Upper Miocene (Messinian) salt as much as 2,000 m thick. The dominant fault movement was pre-salt and there is little evidence of post-salt reactivation along the Rosetta trend.
In contrast, the Temsah trend shows Pliocene wrench-fault activity (Figure 6b) contemporaneous with the oblique subduction of the African Plate beneath the Cyprus Trench. The tectonic activity appears to have triggered pillowing of the Messinian salt throughout the Pliocene to create a distinct Diapiric Salt Basin (see Figure 5) with ponding of strata in mini-basins. Uplift of part of this basin to form the Inverted Salt Basin in the east and toward the Eratosthenes high is associated with the wrench faulting.
The interaction of the two major faults within the Block has produced a variety of structural styles. In addition to brittle deformation related to fault movement, salt tectonics deformed the Pliocene-Pleistocene sedimentary section to create diapiric structures, salt walls and sediment ponding between the salt domes.
The southern margin of the Messinian salt basin appears to be fault controlled. This is indicated by the sudden change in structural styles across an east-west lineament (Figure 6c) from the stable Platform in the south to the Rotated Fault Blocks domain to the north. Although some degree of gravity gliding over the salt has been identified, the location of the Rotated Fault Blocks domain was probably controlled and triggered by deep-seated basement uplift. The domain is on the southern margin of the Messinian Salt Basin, the trend of which is parallel to the active plate margin between the African and Turkish plates that lies south of Crete and Cyprus. The Messinian Salt Basin is cut by a NW-trending pre-salt structural ridge flanked by thick salt pods, diapiric structures and associated salt. Seismic facies analysis of the evaporitic sequence indicates three distinct cycles of salt deposition.
In the western part of the Deepwater Block, the northern boundary of the Platform coincides with the southern limit of the Messinian salt. Here, the northward roller-pinning of the salt forms a succession of large E-trending normal faults that are replaced northward by large, salt-induced anticlines. Gravity data show a prominent E-W anomaly coinciding with the main platform-bounding fault, and it is likely that this fault, at least, has a deep-seated origin.
Northeast of the Platform-bounding fault, the NE Mediterranean Deepwater block is characterized by Pliocene mini-basins and widespread diapiric salt. The mini-basins were filled by rapid sediment influx from channels in the Platform area. Salt movement continued until recent times, and much of the succession is steeply dipping and truncated at the sea floor. The northern part of the block is characterized by thick, shallow salt deposits and by widespread thrust faults. The thrusts are offshoots of the Temsah strike-slip faults.
The integration of the newly acquired gravity and magnetic data has confirmed the variety of structural domains that highlight basement highs and lows (Figure 7) and the location of major basement faults. Geological models developed using seismic data have been tested against the observed gravity and magnetic measurements. The 2-D and 3-D gravity models indicate a sedimentary thickness of 5 to 12 km (Figure 7) that, in addition to Pliocene and Miocene sediments, consists of a largely uncalibrated pre-salt succession. This thickness of sediments could contain all the main source rock intervals observed in the surrounding areas.
STRATIGRAPHY AND RESERVOIR PREDICTION
Three major stratigraphic levels have been investigated and all have attractive hydrocarbon potential; they are:
Pliocene turbidite system;
Miocene shallow-marine system grading laterally into the Messinian salt province, and;
Hydrocarbon discoveries have been made within equivalent petroleum systems in shallow-water areas of the Nile Delta proper. The Pliocene deposits consist of slope and basin-floor turbidites in the form of channel/channel-levees and sheet sands (Figure 8). Late Miocene submarine canyons that were formed due to the lowering of sea levels during the Messinian salinity crisis may contain shallow-marine and turbidite systems. The pre-salt section could contain several types of reservoirs, such as Miocene reefal-limestones overlying seamounts (see Figure 6a) and Miocene turbidite sands in large, wrench-faulted structures.
Tectonic activity throughout the late Mesozoic and later periods resulted in a variety of structural styles. These styles influenced the pattern of sediment transport into the Mediterranean basins (Ross et al., 1977; Vail et al., 1977; Rizzini et al., 1978; Posamentier et al., 1988; May, 1990; Abu El Ella, 1990; El Heiny et al., 1996). The Pliocene and Upper Miocene sections are thought to contain the principal reservoir targets in the Block.
Well calibration and seismic facies mapping in the Nile Delta area indicate that throughout much of the Pliocene, the area of the eastern Mediterranean was a deepwater environment, transitional between slope and basin floor (Figure 9). Overall, the Pliocene section shows a basinward progradation through time. Seismic facies analysis allows the subdivision of the Pliocene into six major depositional cycles that together form the Pliocene Nile Delta system. These cycles contain an overall prograding shelf to slope system and a basin-floor setting where the occurrence of sheet sands is likely.
Throughout the Pliocene succesion the southern area of the Deepwater Block was characterized by N-trending linear turbidite channels as much as 5 km wide that can be mapped for distances of up to 120 km (Figure 9). The channels are typically aggradational, with seismic facies and compaction features indicating gross reservoir thickness of over 100 m. Channel thicknesses typically decrease outboard to between 30 and 40 m.
In the west of the Block, the fault bounding the Platform marks a transition from channels to channeled sand sheets. Overall, the net/gross ratio is low, but sands are concentrated in discrete stratigraphic intervals. This pattern continues outboard, with gradually diminishing sand content and a general thinning of the section. In the east, syn-depositional uplift on the Temsah trend seems to have diverted platform channels toward the northwest. Channels recognized within the mini-basin sequences probably originated from the Temsah fault trend to the southeast.
Local and worldwide analogs suggest that the Pliocene sands are likely to be unconsolidated and of excellent reservoir quality with porosity values of between 24 and 36 percent. Net sand content over the discrete sand-prone intervals is expected to range between 30 and 90 percent.
High-resolution stratigraphic prediction has been carried out with the aid of 2-D stratigraphic forward modeling. The model (Figure 10) is constrained by subsidence calculated from seismic and well data, global sea level curves, fault movements, sediment input rates and depositional gradients. The model allows the identification of higher-order cycles, the nature and geometry of important sequence-stratigraphic boundaries, the prediction of depositional environments and, importantly, the prediction of turbidite-prone intervals.
Confined and Unconfined Settings
Selective reactivation of old faults and/or salt diapirism has resulted in a confined channeled-slope setting in the eastern part of the Block, whereas the western slope setting is relatively unconfined (Figure 11). Seismic identification of channels appears to be straightforward, but prediction of basinal sheet-sand deposits is more difficult due to the absence of any local calibration. The occurrence of distinct onlapping patterns at the base of the slope/basin-floor setting indicates gravity-flow deposits.
Channels in Rotated Fault Blocks
Pliocene-Pleistocene isopach maps show that the main axis of Pliocene sedimentation trends southeastward across the Rotated Fault Block domain. The sediment channels that provide an attractive exploration target are cut by large, salt-induced faults. Outboard, seismic interpretations indicate the presence of large, unfaulted anticlines.
Basin Floor Sheet Sands
Structural closures are observed in the basin floor setting where onlap patterns suggest ponding of sheet sands.
Upper Miocene Reservoirs
The primary Upper Miocene reservoir sequence in the Platform area is of late Messinian age (Abu Madi Formation equivalent). It was deposited in a complex deltaic/shallow-marine setting in, and basinward of, major fluviatile canyons (Figure 12).
The late Messinian deposits overlie anhydrites (Rosetta Anhydrite equivalent) and/or an age-equivalent unconformity surface (Intra-Messinian unconformity). These, in turn, overlie the lower Messinian (Upper Qawasim Formation equivalent) sequence of immature sediments in a canyon setting (Figure 13) that forms a secondary exploration objective. The Upper Qawasim Formation was deposited during rapid downcutting resulting from the pronounced Messinian sea-level falls. Outside the canyon area, the Upper Qawasim sequence changes to parallel-bedded sheet sands, as represented by reservoirs in the Abu Qir field (Figure 2). The Rosetta Anhydrite is widespread in the Nile Delta but is absent from the fluvial- to shallow-marine upper Messinian Abu Madi Formation. There, the canyon-fill is inferred from seismic data to be chaotic, sand-prone and up to 300 m thick.
The Platform-bounding fault is thought to mark the transition between the canyon system and deeper marine reservoir facies. In the western part of the NE Mediterranean Deepwater Block, mapping of the Miocene package immediately above the Messinian salt indicates that turbidite sheet sands onlap the developing salt ridges (Figure 14). Seismic data show a basement high oriented toward the northwestern corner of the Block and having a thin salt cover. It appears to have funneled the turbidities to the outboard area.
In the eastern part of the concession, a platform ridge related to the Temsah fault may have hindered the development of canyons and there is no evidence of time-equivalent sheet sands deeper in the basin.
Reservoir quality is likely to vary according to the depositional environment. Canyon fill will tend to be of lower quality (porosities 20–28%), whereas sheet sands are likely to be of excellent quality and have porosity values as high as 32 percent.
HYDROCARBON PLAY TYPES
Platform: Pliocene Channel Play
The Pliocene Channel Play consists of slope/basin-floor turbidites in channel, channel-levee and sheet sand systems in subtle structural closures on the Platform and on large fault blocks and salt-induced anticlines, and around diapiric structures.
Traps are formed by channels crossing 4-way closures or structural noses. Evidence from seismic surveys shows the widespread presence of amplitude anomalies at various, stacked levels throughout the Pliocene section (Figure 15). The prospectivity of the Pliocene channel play (Figure 9) has been demonstrated by successful wells south of the Block (Seth, Ha’py, Osiris, Seti, Rosetta, Scarab and Saffron discoveries).
Platform: Upper Miocene Canyon Play
The Upper Miocene depositional system offers attractive exploration opportunities. It may prove to be the prime target in the deepwater area due to the variety of depositional environments (fluvial, shallow marine reservoirs and/or deepwater turbidite sands) the sequence may contain. During the Late Miocene Messinian salinity crisis, large, deep canyons were cut along the margin of the salt basin, while salt deposition (cyclic in nature and associated with the repeated cut-and-fill sequences), occurred in the basin.
The canyon system has a northwesterly trend (Figures 12 and 13). They are filled updip by proven fluvio-marine systems, but downdip toward the transition into the salt basin a turbidite system is more likely to be present. The play is well established in the Platform area, where several structures south of the Block (Abu Madi, El Qar’a and Baltim fields) contain gas accumulations in the 1 trillion cubic feet (TCF) to 3 TCF range. Prospects consist of subtle structural traps within a large Messinian canyon system (Figure 16).
Rotated Fault Block Play
The southern limit of the Messinian Salt Basin is marked by major E–W-oriented, rotated fault blocks. They were formed by the northward displacement of salt by Pliocene sedimentation. The upthrown fault blocks form large structural closures that are important exploration targets (Figure 17), and amplitude support indicates the likely presence of gas and/or oil charge in thin, more distal and channeled sheet-sand reservoirs.
Diapiric Salt Basin Play
The Diapiric Salt Basin Play covers the eastern half of the Block where it is characterized by major intersecting strike-slip zones. This area has the thickest Pliocene section because of deposition in mini-basins created by salt withdrawal. Slicks attest to the presence of an oil charge that has migrated along strike-slip faults and through salt windows. Reservoirs consist of sheet sands correlated with channels mapped in the Platform area, as well as channel-levees formed alongside channels that originated to the southeast. Seismic profiles indicate a high degree of deformation that has provided a large variety of trap configurations. Subtle structural closures in shallow-marine sands were recognized, and turbidite-sand pinch outs or over-salt anticlines represent attractive exploration targets.
Basin Floor Fan Play
The northern bounding fault to the Platform marks the approximate northern limit of the Messinian Canyon Play. Sheet sands (Figure 18), interpreted as alluvial fans distal from the Messinian canyons are an attractive reservoir objective in the northwest of the Block. The sands are confined to a relatively narrow, NW-oriented corridor north of the Platform that is thought to coincide with an area of thin salt, and hence to have better potential to receive charge. To date, only a very coarse seismic grid is available in this ultra-deepwater area, which nevertheless indicates attractive hydrocarbon-trapping possibilities.
Very little is known about the pre-salt section in the northern part of the Block. Gravity data indicate a 10-km-thick section below the salt that may contain potentially prospective Miocene, Oligocene, Cretaceous and Jurassic sediments. Elsewhere, these sediments are reservoir and source rocks. For example, sands of Middle Miocene (Tortonian-Serravallian) and Oligocene age are the main reservoir units for the Temsah, Abu Zakn, Wakar, Kersh, Port Fouad Marine and Tineh fields in the eastern part of the Nile Delta.
Seismic profiles show that the section below the Messinian Salt Basin is well defined in the eastern part of the Block but that mappable stratigraphic units are more difficult to identify farther west. Large potential reservoir structures mapped at the base of the salt are attractively located with respect to availability of charge. In addition, the Miocene geological setting was favorable for shallow-marine carbonate growth on intrabasinal highs (or seamounts), as proven on the nearby Eratosthenes Seamount. A possible carbonate build-up is interpreted in the northern part of the Block overlying a condensed pre-Miocene section (see Figure 6a). The pre-salt section could contain several types of reservoirs, such as Miocene reefal-limestones overlying seamounts and Miocene turbidite sands in large, wrench-faulted structures (see Figure 6a).
The Pre-Salt Play has all the ingredients of an attractive oil play with potentially large trap capacities but it is challenging because it underlies a considerable thickness of salt. Although the potential is enormous, risks are high and the play is presently considered less attractive than shallower options.
Source Rocks and Hydrocarbon Prediction
The absence of well data from the NE Mediterranean Deepwater Block means that much of the charge modeling in the northern part of the Block is speculative. Gravity data can be modeled to show the presence of a pre-salt section as much as 10 km thick (see Figure 7) that may contain Miocene, Oligocene, Cretaceous and Jurassic sediments. Source rocks of equivalent ages occur in the Nile Delta area and it is probable that at least the Upper Cretaceous black shales contain good-quality source rocks with a high content of Total Organic Carbon (TOC) (Figure 19). Given the significance of the Platform-bounding fault, the presence of Oligocene-Miocene rocks (considered the main source of Nile Delta gas/condensates), is also likely. In addition, Pliocene sapropels with exceptionally high TOC values are present in deep, untested marine source rocks across the fault.
Maturity models for the outboard area are uncalibrated. Although heat-flow measurements have been made in the shallow part of the Nile Delta (Morgan et al., 1977) and in Cyprus, these are probably not representative of the Deepwater Block. Because of the heightened tectonic activity and the presence of salt, it is likely that much of the Block has a heat flow that is higher than in the Delta. Data from the Block confirm very warm (13.8°C) sea-bottom conditions at depths of 2,000 m. The presence of hydrates in a restricted water-depth interval narrows the likely heat-flow range considerably. For the purposes of modeling, a heat flow of 40 to 50 Heat Flow Units was assumed.
Proven gas accumulations suggest that the southern part of the Block is likely to be gas-prone. Farther north, maturity modeling indicates mixed oil and gas charges from various source rocks. The transition is thought to occur in the area of the main Platform-bounding fault. High-quality oil slicks along major strike-slip faults (Figures 19 and 20a) indicate the presence of a liquid charge. In addition, direct indicators of hydrocarbons can be interpreted from the seismic data (Figure 20b).
Given that the basal Pliocene section is only marginally mature at best, it is likely that the charge would be mainly pre-salt in origin. However, access to oil charge in particular could be difficult within the salt basin, although the slicks confirm that the movement of charge is possible through the salt. In addition, salt displacement in much of the area immediately north of the platform-bounding fault means that the Pliocene section is grounded, so providing ample salt windows for charge access.
The discovered hydrocarbon resources in the Nile Delta are gas/condensate-dominated in the central part of the delta whereas oil discoveries have been made at the western and eastern margins of the Delta (Figure 20a). The difference in charge is interpreted as being due to differences in the depth of burial of the source rocks. Thermal and subsidence modeling indicate that whilst the main source rocks in the central parts of the Delta are gas-mature or overcooked, they occur within the oil-generating window at the margins and toward the Block.
The NE Mediterranean Deepwater Block is an area of 41,500 sq km located north of the main gas/condensate-producing Nile Delta. It is characterized by:
Several distinct structural domains, namely: Platform; Rotated Fault Blocks; Basin Floor; Diapiric Salt Basin; and Inverted Salt Basin. The structural pattern is the result of a complex interplay between the major fault trends of Rosetta (NE-trending) and Temsah (NW-trending).
Along the Rosetta trend, Late Cretaceous to early Tertiary transpressional structures are onlapped and covered by a pre-salt sequence as much as 3,000 m thick. These sequences are interpreted as being late Paleogene to Late Miocene age. They consist predominantly of deepwater sediments with local condensed equivalent sequences on syndepositional intrabasinal highs. The Late Miocene pre-salt sequence appears to shale-out westward across the Rosetta trend to become strongly deformed by mud diapirism and gravitational faulting.
Complex deformation took place along the Temsah trend, with the dominant fault movement being in late Tertiary to Recent times. This was associated with large-scale north-verging uplift, the inversion of part of the Messinian Salt Basin, and recent strike-slip faulting that is most intense in the Levant area.
Turbidite and shallow-water depositional systems. Basin-fill models calibrated by detailed stratigraphic analysis in the explored part of the Nile Delta predict a variety of turbidite environments affected by syndepositional fault movement and by mobile salt. These settings coexist along strike with a graded slope on which unconfined turbidite deposition occurred in slope channels with the potential for sheet sands in fault-induced depressions.
Three major stratigraphic levels—the Pliocene turbidite system, the Miocene shallow-marine system grading laterally into the Messinian salt province, and the pre-salt system—have attractive hydrocarbon potentials. Hydrocarbon play types are Pliocene Channel, Upper Miocene Canyon, Rotated Fault Block, Diapiric Salt Basin, Basin Floor Fan, and Pre-Salt.
Possibilities for discovering gas, gas/condensate and oil are good. The prospectivity of the Pliocene Channel Play has been demonstrated by discoveries in the Seth, Ha’py, Osiris, Seti, Rosetta, Scarab and Saffron gas fields. The Upper Miocene Canyon Play has proved successful in the Abu Madi, El Qar’a and Baltim gas fields. Upthrown fault blocks of the Rotated Fault Block Play form large structural closures that make important exploration targets. Attractive exploration targets exist in the salt basin domain and in the sheet sands of the Basin Floor Fan Play. The Pre-Salt Play is challenging because of its location beneath a considerable thickness of salt. The potential of the Pre-Salt Play is enormous but the risks are high and at present it is considered less attractive than shallower options.
The authors thank the management of Shell Egypt for allowing them to publish this paper. We are indebted to the members of the Shell Deepwater SEPTAR and SDS for their constructive comments and discussions. We appreciate the geochemical interpretation by Magda Nour El Din, the seismic AVO interpretation support of Ahmed Awad and Ahmed Helmi, and the assistance of Shell Egypt draftsman Mohamed Hindy. The design and drafting of the final graphics was by Gulf PetroLink.
ABOUT THE AUTHORS
Ahmed Abdel Aal joined Shell in 1997 having spent the previous 16 years in GUPCO (Amoco Egypt joint venture Company). Ahmed worked in the NEMED Deepwater Team and is currently with the Regional Deepwater Team in Houston, Texas.
Ahmed El Barkooky joined Shell Egypt in 1995 as a Senior Stratigrapher. He is currently working on the regional stratigraphy and depositional systems of the Nile Delta in relation to the Mediterranean Ultra Deepwater Area. Ahmed has a PhD from Cairo University.
Marc Gerrits joined Shell in 1986 and has had postings in Australia, UK and Angola. He joined the NEMED Deepwater Team in 1999.
Hans-Jürg Meyer joined Shell in 1984 and has worked as a Geophysicist/Seismic Interpreter in Libya, Gabon, The Netherlands and Pakistan. In 1997, he moved to Shell Egypt and is currently working in the NEMED Deepwater Team.
Marcus Schwander joined Shell in 1984 at the E&P Research Laboratory in The Netherlands and has subsequently worked in Norske Shell and in New Business Development in The Hague. Marcus moved to Shell Egypt in 1997 and is Project Manager for Shell’s Deepwater Exploration Acreage. He has a PhD from the University of Basel.
Hala Zaki joined Shell in 1995 after several years working for Deminex Oil Company, Egypt. In 1998 she returned to Shell Egypt after secondment to PDO. Hala is a Seismic Interpreter in the NEMED Deepwater Team.