An overview on selected Middle Miocene slope channel complexes, offshore east Nile Delta of Egypt

An overview on selected Middle Miocene slope channel complexes, offshore east Nile Delta of Egypt

Journal of African Earth Sciences 112 (2015) 150e162 Contents lists available at ScienceDirect Journal of African Earth Sciences journal homepage: w...

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Journal of African Earth Sciences 112 (2015) 150e162

Contents lists available at ScienceDirect

Journal of African Earth Sciences journal homepage: www.elsevier.com/locate/jafrearsci

An overview on selected Middle Miocene slope channel complexes, offshore east Nile Delta of Egypt Essam F. Sharaf a, *, Khaled A. Khaled b, Ahmed I. Abushady c a

Geology Department, Faculty of Science, Mansoura University, Mansoura 35516, Egypt Geology Department, Faculty of Science, Helwan University, Helwan, Egypt c BP, 14 Road 252, Maadi, Cairo, Egypt b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 28 March 2015 Received in revised form 23 August 2015 Accepted 16 September 2015 Available online 26 September 2015

Middle Miocene turbidite channel reservoirs offshore Nile Delta of Egypt are difficult to develop efficiently. The depositional mechanism of these channels defines sand bodies with variable thickness and quality over short distances. Akhen Field is a turbidite high pressure and high temperature reservoir offshore in the East Nile Delta, Egypt. The turbidite deposits at Akhen area reflect varied depositional fabrics from poorly to moderately sorted and non-graded to graded. Well logs and core data suggest at least 3 sand packages in a cyclic pattern. Each package exhibits variable sedimentological and petrophysical properties and forms a separate reservoir, sealed by shale. A conceptual geologic model showing facies geometry based on 3D seismic mapping and core analysis was used for evaluation of the reservoir quality of the Field. Integrating sedimentologic and other subsurface data such as seismic attributes, pressure data, core analysis, was crucial to predict the fluid flow between the different reservoir units. © 2015 Elsevier Ltd. All rights reserved.

Keywords: Miocene Turbidite channels Seismic interpretation Offshore Nile Delta

1. Introduction Turbidite reservoirs are one of the most significant targets of deep-water hydrocarbon exploration worldwide (e.g. offshore Gulf of Mexico, Angola, Egypt, Brazil … etc.). Recent exploration activities and application of advanced technologies resulted in understanding of the depositional architectures and facies distribution of the turbidite reservoirs. Despite drilling and development challenges associated with pre-Pliocene prospects offshore Nile Delta of Egypt, Middle Miocene reservoirs are considered to have the greatest potential for hydrocarbon exploration (Dolson et al., 2001). These challenges are low-resolution of seismic data due to the masking effect of the overlying Messinian evaporites, overpressure due to thick overlying rock column, and limited number of drilled wells. Middle Miocene turbidite reservoir geometries, interpreted from 3D seismic data, are critical for future development of this area, particularly where the well data is missing. The best examples of these reservoirs are the Akhen and the Temsah Fields which are estimated to contain

* Corresponding author. E-mail address: [email protected] (E. F. Sharaf). http://dx.doi.org/10.1016/j.jafrearsci.2015.09.011 1464-343X/© 2015 Elsevier Ltd. All rights reserved.

more than 2 TCF of recoverable reserve (Bertello et al., 1996). Regional analogs of turbidite channel architectures are used to understand the geology of Akhen channels. Among these examples are, Flood and Damuth (1987), Babonneau et al. (2002), Mayall et al. (2006), Kolla et al. (2007) … etc. Similar work published by Roberts and Compani (1996), Kolla et al. (2001), Posamentier and Kolla (2003), Samuel et al. (2003), Deptuck et al. (2003, 2007) and Kolla et al. (2007), Cross et al. (2009), Sharaf et al. (2015) is also important to understand the channel geometries using 3D seismic attributes and well logs. Facies variation within the different channel segments can be used to predict the reservoir quality and fluid flow through the turbidite reservoirs (Slatt, 2006; Schwarz and Arnot, 2007). Pressure data obtained from the different channel segments particularly the fine grained lithology is a good indicator of potential path for hydrocarbon flow through the reservoir (Holman and Robertson, 1994; Kendrick, 2000). The objectives of this article are to: (1) interpret the depositional architecture and facies distribution and reservoir geometry of the Middle Miocene channel-levee and sheet system at Akhen Field area, and (2) speculate on the patterns of connectivity and dynamic flow through the Akhen Field.

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Akhen is a gas and condensate Field, discovered by BP Amoco in 1996 by the drilling of Akhen 1 exploratory well. The Field lies beneath 80 m (262 ft) of water and is located approximately 56 Km (34.8 mile) north east of Damietta promontory (Fig. 1). The Field lies within the Ras El Bar concession on the western flank of the NWeSE Temsah-Akhen structure. All reserves come from Middle Miocene, Sidi Salem, sand reservoirs (Fig. 2). Production commenced through the first appraisal well, West Akhen 1 (WA1) that was drilled in 2001. Subsequently, two more wells (Fig. 3); West Akhen 2 (WA2) and West Akhen 4 (WA4), were drilled in 2002 and 2004 respectively. The reservoir intervals at Akhen Field are called Sand 1, 2a, 2b, 3a, 3b and 3c (Figs. 4 and 5) A subsurface study of the Middle Miocene reservoirs at the Akhen-Temsah area (Fig. 1) was initiated by Bertello et al. (1996) and followed by Carbonara and Lottaroli (2003) and Marten and Shaan (2004). The nearby Temsah Field (25 Km) is considered as a good analog to Akhen Field (Fig. 1), as it includes the same stratigraphic intervals and depositional architectures of the reservoir packages. However, limited cores, low quality of seismic data particularly at Temsah area and absence of consistent stratigraphic markers complicate the lateral correlation between the two Fields. Rapid lateral facies changes, paleo-topography and accommodation rate differences complicate the basin architecture Carbonara and Lottaroli (2003). The stratigraphy of Akhen reservoir is based of high resolution biostratigraphic analysis of cores and selected cuttings from the reservoir intervals. The stratigraphic analysis includes analyzing the identified foraminiferal, nanno-planktonics and palynologic fossil groups. The identified biozones did not help to define a consistent biostratigraphic framework along the Akhen reservoir. Few nanno-planktonic zones tied with seismic interpretation and were used to date the Akhen sand. The age of Akhen sand is bounded between Langhian e Serravallian ages (Fig. 2), NN5a and NN6 biozones.

2. Geological setting The geologic evolution of the Nile Delta can be traced back to the Late EoceneeOligocene time when deltaic facies occurred west of the present Nile Delta as a result of a northwest shift in the discharge of the ancestral Nile (Said, 1990). This fluvio-deltaic setting continued through the Early Miocene with a possible

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increase in the rate of subsidence of the North Delta Block (current offshore Nile Delta) that was dominated by sandy fine-grained turbidites. During the Middle Miocene, the North Delta Block was dominated by listric faults and half grabens that developed in the central and eastern areas (Fig. 2). The depositional environment continued to be outer neritic to bathyal (Said, 1990; Khaled et al., 2014). The other areas to the west and south of the Nile delta were affected by a regional uplift with an eastward shift of the deltaic deposition (Sestini, 1989). The Tortonian is characterized by marked uplift of the southeast hinterland with active erosion of the Nubia Sandstone and basement rocks that resulted in dominance of coarse-grained sand deposits. The Tortonian clastics indicate significant syndepositional movements along the flexure zone with development of a few depocenters. The facies distribution reflects considerable variability of marginal, deltaic to lagoonal environment (Sestini, 1989). The Messinian was marked by thick evaporite deposits associated with desiccation of the Mediterranean Sea (Hsu, 1983). The eastern side of the Nile Delta is marked by unconformity surface between the Middle Miocene and Pliocene, particularly at the Akhen-Temsah area, as indicated by the drilled wells. Few wells penetrated relics of Messinian evaporites. An Early Pliocene marine transgression extended inland and submerged up thrown faulted blocks of the Nile Valley. The Late Pliocene was marked by regional deltaic progradation and fluvial deposition due to humid conditions and regression of an Early Pliocene sea northward (Dixon and Robertson, 1984). Akhen Field lies across a large compressional NWeSE anticline of Middle Miocene age (Fig. 3) and represents an along-strike extension to the Temsah Field (Khaled et al., 2014). The reservoir forms a combined structural-stratigraphic trap of deep-water channel-levee and sheet complex system draped over structural closures. The Akhen reservoir unconformably overlies the Lower Miocene, Qantara flooding surface. In the Akhen Field area, where dissolution of the Messinian evaporites was active, the Middle Miocene reservoirs are sealed on top by the Lower Pliocene unconformity. The top seal at the Temsah Field area is the Messinian evaporites (Barsoum et al., 1996).

3. Seismic interpretation The structure of Akhen Field is covered by two 3D seismic data

Fig. 1. Map showing the location of Akhen field and its surrounding Temsah field. The AeA0 line shows the direction of the cross section illustrated in Fig. 3.

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Fig. 2. Structure map of Akhen field showing the anticlinal structure of the Miocene reservoir near sand 1 top and location of the drilled wells.

Fig. 3. AeA0 structural cross section across offshore East Nile Delta, showing the structural geology of post and pre-Messinian plays (Modified after Dolson et al., 2001). The geologic column and ages of reservoirs and source rocks are adapted from BP.

sets acquired in 1995 and 2003. The 1995 vintage was recorded with dual sources and dual receivers, with a fold of 40. The primary target of this survey was the nearby Ha'py Pliocene reservoir. The 2003 survey was recorded with single source and the fold is 104. This data set was reprocessed in 2007. The ties of the synthetic and VSP to the reflectivity data at zero phase of the reprocessed 2003

3D seismic data set in the Miocene section are good (Marten and Shaan, 2004). Rock property studies indicate that the sand exhibits higher acoustic impedance relative to shale. Interpretation of vertical seismic amplitude profiles along WA1 and WA2 wells (Fig. 4) was based on using black reflector as positive reflection coefficient (peak) which generally correlates to

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Fig. 4. EeW seismic reflectivity profile across strike of Akhen wells showing the different seismic signatures and the synthetic ties. The black color refers to sand and the white color refers to shale. The interpreted lines refer to the top sand horizons. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)

presence of sand. The white reflector indicates negative seismic amplitude (trough) which generally correlates to presence of shale. The change of the amplitude is also expressed by the plot of windowed root mean square (RMS) amplitude maps of all the reservoir sand units. The RMS is a statistical measure of the magnitude of a varying quantity. It is especially useful when variants are positive and negative, e.g., waves. The correlation between the amplitude maps and the presence of sand lithologies was further confirmed from the logs and cored interval of the WA1 and WA2 wells. Geo-probe software was used in this study for visualization of the channel geometeries using Geo-Anomalies feature. This feature is a tool that uses the power of the computer to extract channel bodies from a 3D volume of seismic data. The Geo-Anomalies feature is based on automated tracking of certain voxels that are not limited by boundaries such as faults or surfaces. The voxel is a volume element, representing a value on a regular grid in 3D space. This is analogous to a pixel, which represents 2D image data. Extracted channel bodies based on volume isolation using amplitude connectivity and size criteria were sorted out and correlated with the channel features interpreted from amplitude maps of the interpreted surfaces. A spreadsheet-type interface with the dimensions, area and volume of each channel body was produced and was used to define channel geometries for each reservoir interval. Spectral Decomposition is another Geo-Probe tool that was used in this study for imaging and mapping channels and delineating their litho-facies. This tool is based on the idea that sediments filling channels resonate at variable frequencies and can be distinguished from one another by their frequency responses. Spectral Decomposition maps produced were compared with other seismic attribute maps to assure better description of the Akhen Field reservoirs. 4. Depositional architecture and stratigraphic framework Fig. 5. (A) Un-interpreted EeW seismic profile, across strike, showing the different stacked horizons at Akhen Field. (B) Interpreted profile showing the proposed channel systems, the main sand units at different stratigraphic levels and their lateral continuities.

Middle Miocene reservoirs at Akhen area are part of the deepwater slope channel system that occurs within the offshore, east Nile Delta (Sestini, 1989; Bertello et al., 1996; Dolson et al., 2001). The Miocene sediments accumulated in offshore east Nile Delta

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area share common characteristics such as being deposited as multi-layered reservoirs with different thicknesses, and genetically consist of complex geometries of channel-levee and sheet sand deposits. Limited and discontinuous cored intervals and poor quality seismic data are the main challenges in understanding the geology of these turbidite deposits. The depositional package in Akhen Field consists of a series of at least 6 sand units (Sand 1, 2a, 2b, 3a, 3b and 3c, Fig. 5). The depositional architecture of each reservoir unit is described below, from youngest to the oldest, as follows: 4.1. Sand 1 reservoir Sand 1 is the shallowest reservoir at Akhen Field. The unit is of Serravallian age and underlies the lower Pliocene unconformity. The reservoir was cored at WA2 well. Sand 1 forms discontinuous reflectors which are difficult to trace confidently across the Akhen area (Fig. 4). The seismic facies analysis of Sand 1 package indicates that it is defined by relatively thin and scattered reflector that thins eastward. This reflector corresponds to thin bedded interval described from the logs and the core taken from WA2 well. This reflection forms the main Sand 1 reservoir unit. The areal distribution of Sand 1 is of limited extent around the drilled wells. Geoprobe mapping using Geo-Anomalies and Spectral Decomposition (17e20 Hz frequency range) features indicate that, the Sand 1 reservoir unit is characterized by low-relief linear feature which corresponds to a complex of channels and channel-levee. The channels are scattered throughout the Akhen Field area and are SEeNW trending. The largest channel body (not penetrated by any well) is located west of WA2 well (Fig. 6AeC). Amplitude mapping of this channel body shows that it forms a sinusoidal feature of variable width to thickness ratio. The channel body range in width from 100 to 200 m (328e656 ft) wide and it is between 20 and 30 m (65.6e98.4 ft) thick (Fig. 6A). The RMS amplitude signature indicates that this channel is filled with sand. The strong amplitude that defines this geology changes into scattered to the east, and is defined in the middle by a thin linear low amplitude feature that is most probably corresponds to a narrow mud-filled channel. This mud-filled channel is bordered, on both sides, by high amplitude areas corresponding to sandy symmetrical levee which is the main reservoir penetrated by WA2 well (Fig. 6A). The sandy levee is about 800e1000 m (2624e3280 ft) wide and 5e7 m (16e23 ft) thick. The Sand 1 unit grades eastward into shale towards WA1 well. However, it forms a thin laminated sand unit of about 4 m (13 ft) thick in the WA4 and Akhen 1 well area. Seismic data at this area indicates that Sand 1 forms isolated sand bodies filling a small-scale confinement. The Sand 1 unit is stratigraphically older than the NN6b nanno-planktonic zone. However, the stratigraphic resolution is not high enough to correlate with the Sand 1 unit identified at WA2 and WA1 well area based on seismic continuity. The core taken in WA2 indicates that Sand 1 is very fine to fine grained thinly laminated and characterized by thinning and fining upward trend. The sand is argillaceous at the top and changes into massive calcareous towards the base. The described sedimentary structures from the core are climbing ripples, ripple cross laminations and wavy laminations (Fig. 7). Petrophysical evaluation of Sand 1, based on the logs of WA2 well, indicates that the total thickness of Sand 1 is 54 m (117 ft) including thin sand streaks and mixed silt and shale lithologies at the top (Table 1). The Sand 1 unit is characterized by an average porosity of 22%, average water saturation of 43%, and a relatively low net to gross of 13% as the thin laminated interval at the top of the massive sand was included in the calculation.

4.2. Sand 2 reservoir Sand 2 constitutes the main producing reservoir at the Akhen Field area. This sand unit is of Serravallian age based on nannoplanktonic data and seismic interpretation. It was cored at the base of the reservoir at WA1 well. The Sand 2 unit pinches out westward as it does not exist at WA2 well. However, the sand is thicker and is distributed over a relatively wider area than Sand 1. It can be delineated as two distinct sand units (Sand 2a and 2b). The upper sand (Sand 2a) is defined by a strong reflector (Figs. 4 and 5). It extends eastward towards WA4 and Akhen 1 wells. The lower sand (Sand 2b) is thinner and grades into shale westward. Geoprobe mapping using Geo-Anomalies and Spectral Decomposition (20e25 Hz frequency range) indicate that the Sand 2a unit forms a wide extensive sand body that thins laterally westward. Sand 2b has a limited extent around the well areas. The GR log signatures show that Sand 2 consists of a relatively thin finning upward interval at the base corresponding to Sand 2b unit and overlain by a thick-bedded interval and a coarsening upward interval. Sand 2a and 2b can be correlated laterally from WA1 to WA4 and Akhen 1 wells. The core taken near the base of Sand 2b in WA1 well (Fig. 8) shows a complex and repeated pattern that represents a series of low-density turbidite flow (Lowe, 1982; Stow, 1986). It starts with poorly sorted conglomeratic lags of pebble to cobble size overlain by coarse to medium, thick massive sand. The massive sand is overlain by thin laminated sandstone and grades vertically to interbedded sand with silt and clay. The dominant sedimentary structures are starved ripple, wavy, convoluted laminations and cross laminations with few horizontal burrows. The thin laminated fine-grained lithologies are probably dominated by Tc and Td in Bouma turbidite sequence that indicates channel abandonment stage Bouma (1962). The contacts between this unit and the overlying units are sharp and erosive. The petrophysical attributes of, Sand 2 units are characterized by 37% net to gross, 22% average porosity and 35% average water saturation (Table 1). The Sand 2 channels are 400e500 m (1312e1640 ft) wide with variable thickness from 20 to 40 m (65.6e131 ft). The average total thickness of the stacked Sand 2 units is 100 m (328 ft). 4.3. Sand 3 reservoir Sand 3 is the deepest penetrated sand unit at the Akhen Field area. The sand belongs to the base of the Middle Miocene, Langhian age. Based on its faunal content and seismic continuity, it is divided into two main intervals; Sand 3a and 3b (Fig. 5). Sand 3a forms a strong seismic reflector at the WA2 well area and pinches out eastward. The equivalent intervals at WA1 and WA4 wells were described as shale dominated (Fig. 5). Geoprobe mapping using Geo-Anomalies and Spectral Decomposition (20e25 Hz frequency range) indicates that the channellevee system is better developed westward towards the WA1 and WA2 well area. The channels are sinusoid and are following the same NWeSE trend of the shallower channels (Fig. 6 EeF). Sand 3a channels are 300e400 m (884e1312 ft) wide and range in thickness from 20 to 50 m (65e164 ft). Sand 3a at WA2 well is gas charged and it consists of 62 m (203 ft) thick of stacked sand packages with finning upward trends separated by thin mudstone beds as indicated from the gamma ray curve. Petrophysical evaluation indicates that the sand has 20% porosity, 52% water saturation and 60% net to gross (Table 1). Sand 3b was penetrated by WA1, WA4 and Akhen 1 wells. However, Sand 3b at WA1 well area is the only sand unit that consists of inter-bedded, mud-dominated lithologies eastward

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Fig. 6. Different channel architectures at Akhen field area. The channels dimensions are obtained from geo-bodies and amplitude maps. Purple and blue colors represent high amplitude (sand-dominated) while red and yellow represent low amplitude (shale-dominated). (A) Amplitude map (20 Hz window) of Sand 1 to the west of WA2 well. The bright amplitude indicates sinusoid sand-filled channel type. (B) Amplitude map (20 Hz window), showing the sandy levee of the mud-filled channel at WA2 well area. The channel trend is NWeSW. (C) Structure map of Sand 1 to the west of WA2 well (shown at B). The figure shows the width, the sinuosity and the orientation of the channel. (D) Sand 1 and Sand 2 channel architectures illustrated using the 3D geo-Anomalies tracking tool. The figure shows the lateral extension of each channel. Sand 2 channel extends laterally with no data to the south of Akhen area. (E) Sand 3a and underlying older channel architectures illustrated by 3D geo-Anomalies tracking tool. The figure shows the eastward lateral extension of Sand 3a channel. (F) Amplitude map of the Sand 3a unit showing the branching of the channels at Akhen area. The best amplitude anomaly, reflecting the sand prone area, is in WA2 well area. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of this article.)

(Fig. 9). Sand 3b is wet as it falls below the gas water contact. It represents the only true aquifer in the Field relative to Sand 1 and Sand 2. The logs show that Sand 3b at WA1 well consists of a relatively thick coarsening upward interval. The core taken in the base of Sand 3b at WA1 well shows that the dominant facies is shale with few thin laminated sandstoneemudstone and debris flow deposits (Fig. 9).

5. Well correlation Correlation of sand units in Akhen wells is challenging due to facies complexity, limited number of cores and lack of nearby analogs. Several methods were used to correlate the different reservoir intervals and sub-units in the Akhen wells. Among these methods is correlation using different fluid geochemistry of the reservoir interval to conclude the fluid pathways and reservoir

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Fig. 7. Core description and different facies types of the Sand 1 unit in WA2 well. The Gamma Ray (GR), Resistivity (RT) and VSHALE (VSH) logs show the vertical variability of the sand quality.

Table 1 Summary of the different reservoir units and their petrophysical characteristics at Akhen field. Well

AKHEN-1 W.AKHEN-1 W.AKHEN-2 W.AKHEN-4

Reservoir unit

Sand Sand Sand Sand Sand Sand

2 2 3b 1 3a 2

Top

Base

Gross interval

Cored interval

Core thickness

Net Pay

AVG PHI

AVG SW

Net/Gross

(Meter)

(Meter)

(Meters)

(Meter)

(Meter)

(Meters)

%

%

%

(Meters)

4292.00 4313.00 4508.00 4373.50 4730.00 5206.00

4410.00 4402.00 4538.00 4401.50 4792.00 5368.00

118.00 89.00 30 28.00 62.00 162.00

NA 4375e4390.5 4537e4555 4380e4395 NA NA

NA 9.75 17.45 15.00 NA NA

26.00 33.19 Wet 6.50 37.00 66.60

18.00 19.00 Wet 22.00 20.00 16.00

34.00 35.00 Wet 43.00 52.00 29.00

0.22 0.37 Wet 0.23 0.60 0.41

52.38 70.00 Wet 22.20 49.80 92.00

lateral connectivity. Other correlations are based mainly on logs and faunal contents of the cuttings and core samples of these wells. Available geochemical data show that each sand layer, within the same reservoir interval, has isotopic gas composition and pressure data that can be laterally correlated throughout the entire Field (BP Internal Report). Each layer forms a separate reservoir unit with a complex filling history (Fig. 10). Biostratigraphic analysis of the core samples and cuttings was used cautiously particularly at the reservoir intervals. Most of the identified species were mixed and lacking broad distribution throughout the Field area. Several biozones can be correlated laterally, particularly at the thin laminated and muddy intervals that are rich in fauna (Fig. 10). The biostratigraphic ages of the sand units were correlated with their seismic interpretations. Sand 1 at WA2 well and its lateral mudstone equivalent at WA1 well are of the same age. The lowest sand interval of Sand 2 at WA4 well is characterized by distinctive fauna and is localized around WA4Akhen-1 area. This interval represents the lowest penetrated sand at WA4-Akhen 1 area. Sand 3a at WA2 (gas bearing) changes laterally into shale towards WA1 well and is younger than the Sand 3b (water wet) at WA1 well. The Sand 3b at WA1 is the deepest

Net reservoir

penetrated sand unit at Akhen Field. 6. Depositional model The Akhen Field represents turbidite channel-levee and sheet complex (Fig. 11). The turbidite channels form at least two of these complex systems (Fig. 5) that are connected at the same reservoir level, but are separated by inter-channel mudstone. Both systems consist of multi-layered channel-levee and sheet complex. The channel geometries are variable, trending SEeNW, and show variable degrees of sinuosity (Fig. 6AeC). Lateral correlation of Akhen wells indicates that Sand 1 and 3a reservoirs are only defined at the western side of the Field and refer to confined channel-levee complex around WA2 well. Seismic mapping west of the WA2 well area shows a wide lateral extension of these reservoirs, which are most probably of channel-sheet complex origin. Sand 2 reservoir unit is defined by more laterally extensive channel-sheet and channel-levee complexes. The channels and levees pinch out eastward and are more developed toward the west. Most channel-fill sediments are not seismically resolved; therefore, channel to channel relationship is not clear. However, the

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Fig. 8. Core description and different facies types of the Sand 2 unit in WA1 well. The Gamma Ray (GR), Resistivity (RT) and VSHALE (VSH) logs show the vertical variability of the sand quality.

Fig. 9. Core description and different facies types of the shale section below Sand 3b unit in WA1 well. The Gamma Ray (GR), Resistivity (RT) and VSHALE (VSH) logs show the vertical variability along the well and the location of the described facies.

cores and logs of Sand 2 unit show that most described channels are amalgamated. The 3D seismic imaging indicates that the Akhen reservoirs are part of unclearly defined MioceneeOligocene

turbidite slope system. The channel-levee complexes are most probably of upper to middle slope setting. However, Sand 3 reservoir channel-levee system is more argillaceous, less amalgamated

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Fig. 10. Correlation of different Akhen wells based on their sand distribution concluded from the logs and biostratigraphic contents that were used to define the different ages based on nanno-planktonic markers. The double arrows refer to possible fluid communication.

than Sand 2, and spreads out (fans out) at the well area. This sand package might have been deposited in deeper conditions, most probably upper to middle fan. The Akhen depositional scenario is not very different from the nearby fields such as Temsah and Osiris. Both of those latter fields are characterized by fairly high degree of variability in channel geometries and facies (Carbonara and Lottaroli, 2003; and Marten and Shaan, 2004). The lateral variability was interpreted as a result of system fed by a constant sediment supply with different entry points (Carbonara and Lottaroli, 2003). Cores taken from EDDM field, 20 Km (12.4mile) to the north (down current) of Temsah-Akhen area, show similar genetic characters and same variability (Carbonara and Lottaroli, 2003). In general, evolution of the Miocene and deeper channel systems is not clearly defined compared to other younger Pliocene and Pleistocene turbidite channels of the Nile Delta such as Scarab, Saffron (Samuel et al., 2003; Magurie et al., 2008), Simian (Bahaa et al., 2008) Sapphire (Farouk et al., 2008) and Sequoia (Cross et al., 2009). 7. Reservoir quality Evaluating reservoir quality of Akhen Filed is crucial for understanding the fluid flow pattern and volumetric calculation of hydrocarbons. The quality of the reservoir units at the Akhen Field is

based on petrographic examination of 40 thin sections, X-ray diffraction analysis (XRD) of 37 samples for mineralogical and clay fraction composition, scanning electron microscopy (SEM) of 10 samples (Fig. 12AeH) and petrophysical evaluations of logs from the four Akhen wells. The permeability and porosity measurements of the core plugs were measured using the Nitrogen permeameter and the Helium porocimeter devices respectively, at COREX labs in Egypt. The petrographic description of the reservoir units was based on thin sections of core samples obtained from Sand units 1 and 2. Petrographic analysis indicates that Sands 1 and 2 are characterized by a wide range in grain size, sorting, and porosity. The average sand size ranges from very fine lower to very coarse upper. Silt to pebble grain size is also common in Sand 2 unit. Grain sorting ranges from poorly to well sorted. The sand units are loose to well compacted and range from sub-angular to sub-rounded. The sand units have variable porosity ranging from 15 to 30%. Both primary and secondary inter-granular porosity types are present. Pore sizes and pore connectivity are highly variable. Pore connectivity is very weak in the shallowest beds in Sand 1 unit and in mud-dominated beds in Sand 2. The sand grains are dominantly quartz (more than 50% of the total volume) with a variable percentage of feldspars (trace to 8%) and clays (Fig. 12AeB). The clays exist as matrix, and grain coatings. The feldspars are mainly orthoclase and microcline with subordinate amount of plagioclase.

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Fig. 11. (A) Depositional model of the Middle Miocene reservoirs at Akhen area. The model is showing the two main channel systems that were penetrated by wells. The model is also illustrating the laterally and vertically stacked channels that form each system. Both channel systems are not completely isolated. (B) EeW cross sections showing the different channel systems penetrated by Akhen wells. (C) Vertical facies variability of each channel package.

The feldspars generally exhibit variable degrees of alterations. Silica overgrowth (Fig. 12CeD), carbonate and pyrite grains (Fig. 12F) are also common in most of the described samples. Petrographic examination and SEM analysis indicate that presence of altered feldspars and clays is the primary control on the reservoir quality. Grain size variation is another factor influencing the porosity and permeability within the different reservoir intervals. Petrophysical evaluation of volume of shale (VSH), porosity and permeability measurements were used to evaluate the reservoir quality for Sand 1, 2 and 3 units (Fig. 11). VSH is estimated from the available shale indicators such as, the Gamma ray curve (GR) and the difference between neutron porosity and density curves. The resultant VSH curve was then calibrated with core results such as the grain size analysis and XRD of the bulk samples. The GR curve is used as a good shale indicator in the Akhen Field reservoirs because of the low content of K-feldspars grains. The other shale indicator used is the difference between neutron porosity and density curves. Low shale content intervals have higher neutron porosity values than density. This is related to the lattice-bound hydrogen in the clay minerals. The larger the shale content, the greater the difference between the two curves. This method was used successfully in the nearby Pliocene reservoir (Ha'py Field), east Nile Delta of Egypt (Bailey et al., 1999). The total porosity was calculated using density and neutron curves. The calculated porosity curves were then calibrated with the core-derived porosity measured from the core plugs of WA1 and WA2 wells. The reservoir quality of Akhen Field wells based on petrophysical characteristics, such as porosity and permeability, indicates

that Sand 2 unit has the best quality compared to other sand units. Sands 1 and 3 have poor quality. The core cut in the basal part of Sand 3b does not reflect the actual sand quality as it did not target the main Sand 3b body. Advanced methods to evaluate reservoir quality have focused on petrophysical measurements. The Winland method (published by Kolodzie, 1980) is based on the relationship between porosity, permeability and pore throat radius at a measurement of 35% mercury. This method is generally reliable in rocks only with intergranular porosity (such as sandstone) where pore and pore throat geometry are related closely to rock texture (Haro, 2004). The rock type is a product of both the depositional and diagenetic fabrics and is directly related to permeability and reservoir performance (Hartmann and Coalson, 1990; Martin et al., 1997). Winland plot is a plot of core porosity, versus core permeability measurements and inferred pore-throat size. In this study, it indicates that there are three main rock types in Akhen sands (Fig. 13). These rock types are correlated with the litho-facies types that each reservoir sand unit contains. Rock type 1 (RT1) is the highest quality sand with the highest porosity and permeability values (Fig. 13). This rock type is limited to the Sand 2a and 2b units at WA1, WA4 and Akhen 1 wells. RT1 corresponds to channel fill sand facies, which represents the main reservoir unit at the Akhen area. Rock type 2 (RT2) is not common at the Akhen Field. It is characterized by moderate porosity and permeability values (Fig. 13). This rock type has been interpreted from the data obtained from both WA2 and WA1 cores and is related to the thin laminated beds that most probably represents the channel abandonment facies.

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Fig. 12. Photomicrographs and SEM photos showing the different sand qualities described from the cores taken in WA1 and WA2 wells. A) Sub-arkosic arenite, medium grained and moderately to well sorted. The most common detrital grains are feldspars (f) and iron oxides (i), Sand 1 unit, WA2 well at measured depth 4393 m, PPL. (B) SEM of the same sand bed showing the dominant euhedral quartz overgrowth (q). The grains are open packed and the main porosity type is intergranular (p). Minor pore filling clay (c) is also encountered. (C) Sub-fedspathic wacke, fine to very coarse grained and poorly sorted. The texture is mud-supported, detrital grains are feldspars (f), mica (m) and lithic fragments (l), Sand 1 unit, WA2 well at measured depth 4392.7 m, XPL. (D) SEM of Sand 1 unit, in WA2 well at measured depth 4387.4 m. The photo shows well developed, euhedral quartz overgrowth (q) and abundant pore-filling chlorite platelets (cl). (E) Feldspathic wacke, silt to very fine grained, moderately to well sorted, with thin laminated mud and low porosity, Sand 1 unit, WA2 well at measured depth 4391.6 m, PPL. (F) SEM of the same bed showing few intergranular pores(p), dispersed clay (c) and aggregates of cubic to sub-cubic pyrite grains (pt). (G) Sub-lithic arenite, medium to coarse grained, poorly sorted, and slightly cemented with few feldspars (f) and abundant intergranular pores(p), Sand 2 unit, in WA1 well at measured depth 4381.1 m, PPL. (H) Lithic arenite, fine grained, well sorted, with abundant iron oxide (i), rock fragment (rf) grains and mica flakes (m). Few feldspar grains (f) and abundant intergranular pores (p) are also encountered, Sand 2 unit, in WA1 well at measured depth 4380.15 m, PPL.

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Akhen Field compared with other reservoir units that exhibit lower quality and hold less hydrocarbon reserves. Akhen Field shows relatively lower reservoir quality and less connectivity relative to the nearby fields such as Temsah and Osiris fields. These fields are located along the depositional strike and share the stratigraphic intervals. Geophysical and sedimentological studies indicate that each of the nearby field is characterized by a separate channel belt with separate entry points for sediment transport that might have affected the variability in reservoir quality from one filed to the other. Acknowledgments

Fig. 13. Interpretation of porosity and permeability measurements from the cores based on Winland plot. The plot shows the different rock types that characterize the Akhen reservoirs. It is noted that RT1 is characterized by high porosity and permeability and larger pore throat than RT3.

Rock type 3 (RT3) is the lowest quality sand with the lowest porosity and permeability values. This rock type has been interpreted from the data obtained from WA2 core and the lower core of WA1 that was taken from the intercalated shale with mudstone beds at the base of Sand 3b. This rock type corresponds to the levee type facies of Sand 1 at WA2 and Sand 3b at WA1 wells. 8. Conclusions Akhen Field represents long-lived slope depositional pathways that accumulated different sand packages, and is bounded above and below by thick fine-grained mudstones and shale. Integrating subsurface data indicates that Akhen depositional pattern forms at least two deep-water channel systems separated by inter-channel mudstone and shale. Each system consists of three stacked sinusoid channel belts trending NWeSW. The channel belts that include the main reservoirs at Akhen Field act as shorter-term flow conduits capped by thin-bedded strata that represent intervening episodes of overbank sedimentation. These thin-bedded intervals act as internal baffles to fluid flow. Within some of these channelized sand deposits, there are a series of recurring features that provide clues as to the distribution of reservoir facies and heterogeneities. High-amplitude seismic imaging and 3D geo-bodies construction obtained from the Geo-Anomalies technique appear to be good indicators of delineating sand-prone lithologies and channels geometries. Channel evolution during the Middle Miocene at Akhen area is not clearly described and deserves to be discussed in future when improving seismic data quality and drilling additional wells. Correlation of the different sand intervals is a useful tool to validate the seismic interpretation and attribute analysis. Biostratigraphic analysis did not contribute in constructing the stratigraphic correlation of the reservoir units. However, it helped in defining the age boundaries of the reservoirs. Connectivity along Akhen reservoirs is not completely understood. However, it is most probably through the channel sheet and sandy levees complexes along the same reservoir interval. Reservoir quality, based on, among other qualifiers, porosity and permeability determination, of Akhen reservoirs is a function of facies types and diagenesis. Production is primarily from Sand 2 reservoir unit which represents the highest quality sand unit at

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