Introduction

The Nile Delta Basin (NDB) is considered a major gas province where numerous trillions of cubic feet of gas have been discovered in the last fifty years in various stratigraphic layers from Oligocene to Quaternary (e.g., Sarhan 2021a, b, c; Sarhan and Safa 2017; El-Fawal et al. 2016; Abu El-Ella 1990; Abdel Aal et al. 2000). Many of the gas detections in the NDB are biogenic. However, there is also a thermogenic source as evidenced by some oil discoveries, especially in the pre-Pliocene (Esestime et al. 2016). The NDB has a gas reserve of roughly 223 trillion cubic feet spread across over 126 gas fields in the cone of NDB (Kirschbaum et al. 2010). In addition to the existence of a considerable biogenic gas component, these fields are assumed to be generated predominantly from mature source rocks equivalent to the Neogene sediments (Vandré et al. 2007).

Since 1963, the Abu Madi Fm. has been the main source of gas in the offshore and onshore areas of the NDB (e.g., Sarhan 2021a; Abu El-Ella 1990). However, in 2000, British Gas and BP corporations discovered the Sienna, Sapphire, Simian, and Taurus plays in the western offshore sections of the NDB, focusing their exploration efforts in these areas. All these plays are part of a Pliocene slope-turbidite (Abdel Aziz and Shann 2005).

The exploration process in the NDB in the 1990s was focused on ultra-deep water from Pliocene turbidite (such as the Ha'py Field). The Lower Miocene-Oligocene sands have yielded recent produced positive results in the NDB, such as, the Raven field (Esestime et al. 2016).

ENI Company drilled a new play in 2015 at a depth of 1500 m near the Egypt/Cyprus border. This play depicts a massive carbonate platform from the Early-Middle Miocene epoch that rests behind a thick layer of Messinian evaporates. Such play was drilled by Zohr-1 Well. This discovery has a total thickness of 628 m with 430 m net pay. The gas volume present is estimated at 30 TCF (Esestime et al. 2016).

The sandstones of the Kafr El-Sheikh Fm. (Early-Middle Pliocene) as well as the El-Wastani Fm. (Late Pliocene) are the most promising opportunities for gas exploration in the Nile Delta's offshore areas (e.g., Othman et al. 2018; Lashin and Mogren 2012; Leila and Mohamed 2020). In general, there are no difficulties in exploring new plays in the Pliocene section of the NDB. However, the high pressure, poor-seismic imaging, and lack of direct hydrocarbon markers are all problems that exist in the pre-Messinian sequence (Dolson et al. 2002). One of the main hydrocarbons plays is the Pliocene sediments in the NDB, which show outboard progradation with time. It has turbidites in the shape of channels, channel levees as well as sheet sands on the slope and basin floor (Abdel Aal et al. 2000). Over the entire rotational fault block, the principal axis of the Pliocene deposition trends SE-NW. Large salt-induced faults cut several underground channels, making them interesting exploration opportunities (Abdel Aal et al. 2000). Successful exploration wells represent the Pliocene channel plays in the offshore NDB such as; Osiris, Seth, Rosetta, Ha'py, Seti, Scarab and Saffron fields (Abdel Aal et al. 2000). The Pliocene slope-turbidite plays (such as; Sienna, Sapphire, Simian and Taurus) are recent discoveries in the western offshore NDB (Abdel Aziz and Shann 2005).

The shallow Pliocene gas reservoirs in the NDB are characterized by visible direct hydrocarbon indicators (bright and flat spots) on seismic profiles, increasing the success rate to about 90% (Dolson et al. 2005; Samuel et al. 2003). Several bright spots inside the Pliocene–Quaternary strata that overlies the Messinian evaporites, which have been drilled with verified gas discoveries in the North Sinai Concession (Ewida and Darwesh 2010). The offshore part of Sinai has favourable hydrocarbon accumulation characteristics and requires more intense investigation (Abd-Allah et al. 2020). Furthermore, the Pliocene–Pleistocene succession of the TAO Field remains intriguing for holding shallow gas reservoirs near to multiple hydrocarbon discoveries that warrants NOSPCO's extra exploration (Ewida and Darwesh 2010). This assessment improves the quality of the gas reservoir and identifies additional economic natural gas reserves in the North Sinai Concession, which is located off the coast of the NDB.

The Baltim Field is the northern continuation of the Abu Madi paleo-valley. It is 500 km2 in size (about 25 km long and 19 km wide) at the offshore section of the NDB and located approximately 25 km from the Egyptian coast between 31.62° and 31.94°N and 31.02° and 31.44°E (Fig. 1). The objective of the present work was to appraise the reservoir quality of the Abu Madi sandstones in Baltim gas-field in the northern part of Egypt’s NDB. This goal achieved by performing the petrophysical evaluation to delineate gas-bearing intervals in five examined wells penetrating the Abu Madi Fm.; Baltim East-2, Baltim East-3, Baltim East-5, Baltim North-1 and Baltim North-2 (also known as the BE-2, BE-3, BE-5, BN-1 and BN-2, respectively). All five wells are inside the Abu Madi paleo-valley at the northern portion of the basin (Fig. 1).

Fig. 1
figure 1

A Regional map represents the location of Baltim Field within Abu Madi Paleo-Valley plus the positions of different gas fields in the offshore sector of the Nile Delta Basin (modified after Sarhan and Collier 2018; Bosworth et al. 2008). B Map displays the available seismic data and the sites of the inspected wells in Baltim Field

Full size image

The construction of 3D seismic attributes as well as 3D reservoir model, that integrates the geological, geophysical and production data of the hydrocarbon reservoir (e.g., Ashraf et al. 2019; Vo Thanh et al. 2019, 2020) in the Baltim Field has not been performed in the current research. This is because the accessible data in this study does not include; 3D seismic survey, core data or a large number of drilled wells. All of these additional data are required to build a reservoir model with high accuracy and low uncertainty (e.g., Vo Thanh and Sugai 2021).

Geologic setting

The NDB is a passive-margin sedimentary basin covering a > 250,000-km2 area in the eastern Mediterranean area (Sestini 1989). It was formed by subsidence, and the subsequent tectonic extension that detached the African–Arabian plate from the Eurasian plate during Upper Triassic–Lower Cretaceous time (Dolson et al. 2001; May 1991). Harms et al. (1990) referred to the southern margin of this east–west rift as the Hinge Zone. The NE–SW normal faults (Rosetta trend) affected the Nile Delta's northwestern part. However, the northeastern part is controlled by NW–SE-striking faults (Bardawil trend) (Fig. 1).

The subsurface Oligocene–Quaternary section of the NDB is ~ 6.0 km in thickness (Hussein and Abd-Allah 2001). The Neogene sediments in the NDB were deposited in sequential regression–transgression cycles under marginal- to open-marine settings (Hashem et al. 2010). This Neogene section is a siliciclastic sequence including (from base to top) the Sidi Salim, Qawasim, Abu Madi, Rosetta, Kafr El-Shiekh, El-Wastani and Mit-Ghamr Fms. (Fig. 2).

Fig. 2
figure 2

Mesozoic–Cenozoic lithostratigraphy of NDB, after Egyptian General Petroleum Corporation (1994)

Full size image

The Abu Madi Fm. consists mainly of intercalated sandstone and shale (Rizzini et al. 1976) formed throughout the Upper Miocene Epoch (El Heiny and Morsi 1992; EGPC 1994) in the final stage of the Messinian syn-rift megasequence, that influenced the subsurface sedimentary section in the NDB (Sarhan et al. 2014; Sarhan 2022). The depositional evolution of the Abu Madi Fm. was intensely influenced by tectonic rather than sea-level changes (Sarhan 2015).

The Abu Madi paleo-valley encompasses proto-Nile distributaries that incised a wide fluvial or canyon system (Fig. 1). This cutting through the preexisting continental shelf of the Mediterranean Sea was related to the significant drop in the global sea in Messinian time (Barber 1981; Harms et al. 1990; Sestini 1989), which resulted in the deposition of the Rosetta Formation, a dense body of evaporites covering the eastern Mediterranean, and the deposition of the Abu Madi Fm. as incised-valley fill. This infilling started as fluvial facies (lowstand systems tracts) followed by estuarine facies (transgressive systems tracts) (Salem et al. 2005).

Data and methods

The obtainable geophysical data for the present study includes thirty-seven 2D seismic sections in addition to the conventional well-log data (gamma-ray, sonic, resistivity, and neutron-porosity and -density logs) accompanied by the composite logs for the five inspected wells (Fig. 1b).

The methodology applied to evaluate the Abu Madi reservoir in the studied field started with the seismic explanation step. This step includes the picking and map** of the seismic horizon corresponding to the base of the Abu Madi Fm. over the grid of the available seismic lines (Figs. 3 and 4). The well-log data were inspected to compute the petrophysical parameters characterizing the hydrocarbon prospects by using Schlumberger’s Techlog computer software. These parameters include shale volume (VSh), total porosity (ΦT), effective porosity (ΦE), and water saturation (Sw).

Fig. 3
figure 3

E–W seismic sections across Baltim Field displays the geometry of Abu Madi incised valley and the wells inside this incision (edited after Sarhan et al. 2022). (See Fig. 1b for the position of the interpreted seismic profiles)

Full size image
Fig. 4
figure 4

A 3D view of the incised valley in Baltim Field showing the geometry of the incision in Baltim Field. B Structure map for the basal surface of Abu Madi Fm. in Baltim Field (modified after Sarhan et al. 2022)

Full size image

These petrophysical parameters were calculated to find the gas-bearing zones in the inspected wells by using Asquith and Gibson’s (1982) equations. VSh values for the examined zones were derived from gamma-ray logs, and ΦT and ΦE were determined from neutron-density logs as displayed in Figs. 5, 6, 7, 8, 9, and 10). Poupon and Leveaux’s (1971) Indonesian model was applied in calculating Sw owing to the presence of shale in the examined pay zones (Figs. 5, 6, 7, 8, 9 and 10). This model comprises a correction to the Archie (1942) equation applicable for calculating Sw where shale is present.

Fig. 5
figure 5

Wireline logs with evaluation exhibiting the gas interval in BE-2 well

Full size image
Fig. 6
figure 6

Wireline logs with interpretation showing the gas zone in BE-3 well

Full size image
Fig. 7
figure 7

Wireline logs with evaluation demonstrating the gas interval in BE-5 well

Full size image
Fig. 8
figure 8

Wireline logs with interpretation exposing the lower gas interval in BN-1 well

Full size image
Fig. 9
figure 9

Wireline logs with evaluation revealing the upper gas reservoir in BN-1 well

Full size image
Fig. 10
figure 10

Wireline logs with interpretation displaying the gas interval in BN-2 well

Full size image

Results

The seismic interpretation showed that the lower surface of the Abu Madi incised valley was visible on the seismic lines. This incised channel is oriented NNW-SSE and has a width of 5–8 km and a length of about 32 km in length.

Visual investigation of the well-log data corresponding to the Abu Madi Fm. in the BE-2 well revealed that the greatest potential for gas reservoir varies within the interval between 3553 and 3602 m depth (49 m thick). In well BE-3, the gas-bearing interval locates between 3633 and 3673 m (40 m thick), and in well BE-5, the best interval was found between 3697 and 3742 m depth (45 m thick). However, the best intervals in BN-1 are varying in depths; 3663–3700 m (37 m thick) and 3738–3786 m (48 m thick). The pay zone in BN-2 well is between depths 3705 and 3730 m (25 m thick). Relevant criteria used to outline these zones in the accessible wells comprise low shale content, confirmed by the low gamma-ray and the high deep resistivity curve (supporting the gas presence). In addition, the density curve is usually to the left of the neutron curve (reflecting the sandstone matrix), and the high values of porosity for the neutron curve confirm the superiority of the examined intervals as potential gas reservoirs (Figs. 5, 6, 7, 8, 9, and 10).

The sandstones of these promising zones in the inspected wells were described in the available composite logs as colorless, greyish-white, greenish grey, off-white, white; fine to medium grained and sometimes coarse grained; subrounded to subangular; poorly to moderately sorted; friable to moderately hard; occasionally cemented by calcareous; glauconitic with traces of feldspars. All these criteria support the high degree of textural maturity for the inspected sandstone intervals.

Quantitative assessment for the examined wells in Baltim field revealed that the total thickness for the interpreted reservoir intervals ranges between 25 and 49 m with net pay thickness varies between 15 and 38.5 m. Consequently, the net to gross ratio (net/gross) within 0.54–0.90 representing highly promising gas reservoir in the Baltim field. The petrophysical calculations for the promising intervals within the Abu Madi Fm. in the considered wells show that average values for effective porosity are between 0.15 and 0.40; shale volume within 0.03–0.20; and water saturation is below 0.50 (Table 1).

Table 1 Summery table shows well locations and the calculated petrophysical parameters for the promising zones within Baltim Field, offshore NDB
Full size table

Pickett (1972) cross-plots that were created for the examined zones (Figs. 11, 12, 13, 14 and 15). Points characterizing the gas zones in the examined wells are clustered and positioned below the Sw = 50% line, reflecting the gas potential of these intervals and confirming the performed petrophysical calculations (Figs. 5, 6, 7, 8, 9 and 10).

Fig. 11
figure 11

Pickett plot for the gas zone in BE-2 well, illustrating that most points are below SW = 50% line, thereby representing gas-bearing interval

Full size image
Fig. 12
figure 12

Pickett plot for promising zone in well BE-3

Full size image
Fig. 13
figure 13

Pickett plot for promising interval in well BE-5

Full size image
Fig. 14
figure 14

Pickett plot for promising zones in well BN-1

Full size image
Fig. 15
figure 15

Pickett plot for gas-bearing zone in well BN-2

Full size image

Such notably converging values of the calculated petrophysical parameters describing the examined intervals suggest reservoir similarity among the Baltim gas fields in the NDB.

Discussion

Despite the discovery of 88 TCF of gas reserve in the NDB, including innovative significant finds (such as the Zohr Field), the geologic setting of the NDB remains weak due to insufficient subsurface data and forthcoming exploration activity (Ismail et al. 2020). Accordingly, the offshore NDB still a neglected wealth of natural gas reserves in Egypt.

In fact, the Pliocene sandstones in the offshore NDB contain significant shallow gas plays, which have recently been, discovered in several locations around the offshore NDB such as; the Kamose and Tao fields. Nevertheless, understanding the diagenetic processes and the reservoir facies is critical for forecasting the distribution of key diagenetic features that regulate the quality of such shallow targets in the NDB and lowering exploration risk (Leila and Mohamed 2020). The pay intervals at Kamose Field vary in thickness between 12 and 74 m representing excellent petrophysical parameters with low water saturation (0.24–0.43), high effective porosity (0.30–0.31), low shale volume (0.21–0.26) and low bulk volume of water (0.07–0.12) (Sarhan 2021c). Moreover, numerous seismic bright spots were delineated on the seismic data close to Kamose field (Fig. 16). These prospects display new gas targets in the Pliocene section at offshore NDB (Sarhan 2021c). On the other hand, the gas-holding intervals in Tao field (Fig. 16) vary in thickness between 4 and 56 m. The computed properties for these reservoirs display highly auspicious characteristics for gas-production; little shale volume (around 0.10); high effective porosity (0.30–0.35), low water saturation (0.10–0.50), low bulk volume water, high values of relative permeability for gas and low in relative permeability to water (Sarhan 2021b). Furthermore, the presence of listric faults and linked rollover folds played an important part in the formation of structural traps for gas-bearing intervals in the Tao Field and its surroundings (Sarhan 2021b).

Fig. 16
figure 16

N–S seismic profile no. 6050 (modified after Sarhan 2021c) displays the locations of Kamose and Tao fields within the Post-Messinian Megasequence in the offshore NDB

Full size image

Furthermore, the existence of growth faults and shale-diapirs within the Kafr El-Sheikh Formation are expected to play a crucial role in the creation of appropriate structural hydrocarbon traps in the Temsah Field. Additionally, the identified single as well as multiple channels intra the Kafr El-Sheikh Formation (Fig. 17) are recommended for extra exploration and drilling activities because they are expected to contain stratigraphic hydrocarbon traps similar to those found in the NDB's western offshore region (Sarhan and Safa 2019).

Fig. 17
figure 17

Interpreted buried channels appear as bright spot features displaying potential gas reservoirs within Kafr El-Sheikh Fm. in Temsah Field (modified after Sarhan and Safa 2019). A NW–SE seismic profile no. L946 displays an example of the single-buried channel. B NW–SE seismic profile no. L1016 displays another example of the multiple buried channel

Full size image

On the other hand, there are several recent gas discoveries in the sandstone beds of the Miocene Sidi Salim and Wakar formations in the offshore region of the NDB, e.g., in the Temsah field (Nabawy et al 2018.). The effective porosity of the sandstones reservoirs within the Sidi Salim Formation in the Temsah field varies between 0.27 and 0.30 with net pay differs in thickness from 48 to 69 m, while, the effective porosity for the sandstones in Wakar reservoirs fluctuates between 0.19 and 0.27 with net pay 9 m thick (Nabawy and Shehata 2015).

The current work suggests a promising target for gas exploration in Baltim Field to assure that the Messinian sequence in the offshore portion of the NDB is also favorable for gas discovery. The present results revealed that the Baltim field is promising target for gas production with net pay thickness fluctuates between 15 and 38.5 m. Moreover, the petrophysical assessment deduced from the electric-log analyses for the examined five wells within Baltim field displayed that the effective porosity for the examined reservoir intervals is high (0.15–0.40) and water saturation is low (< 0.50) as summarized in Table 1. The deposition of the Abu Madi Formation was influenced by tectonics as it represents the uppermost portion of the Messinian syn-rift mega-sequence in NDB (Sarhan et al. 2014; Sarhan 2015). Nevertheless, these results confirm that the effect of the buried normal faults associated with the syn-rift tectonics is limited across Baltim gas field.

It is of worth mentioning that, the well-organized workflow of artificial neural network besides the other geostatistical modeling interactive approaches are highly endorsed in the study area to perform an excellent history matching for the petrophysical properties and lithofacies modelling in the Abu Madi fluvial sandstones (e.g., Vo Thanh and Sugai 2021; Ashraf et al. 2021). Therefore, extra geophysical data in Baltim Field and its surrounding along the Abu Madi incised valley (e.g., 3D seismic data, core data, production data,….. etc.) is highly suggested to perform such techniques. Moreover, the construction of lithofacies maps (e.g., sand-ratio maps) as well as isoparametric maps are extremely recommended to examine the distribution of the sedimentary facies plus the petrophysical properties within Baltim field. Accordingly, the favorable gas zones will be accurately delineated (Anees et al. 2022; Ali et al. 2022).

Summary and conclusions

  • The petrophysical assessment across the examined intervals in Baltim field reflects the homogeneity and lateral continuity for the gas-bearing sandstone of Abu Madi Formation across the inspected paleo-valley.

  • The gas intervals in the inspected wells display good petrophysical parameters for being potential gas-reservoirs with low shale volume (< 20%), high effective porosity (15–40%) and low water saturation (25–50%).

  • The integration of 3D seismic and core data are essential tools for better understanding of the reservoir facies distribution and petrophysical characteristics of the Late Messinian Abu Madi sandstones in Baltim field, offshore Nile Delta Basin.

  • As a recommendation, more exploration activities should be performed for the Pliocene as well as the Messinian sandstones across the offshore Nile Delta Basin.

  • Artificial neural network is highly endorsed to achieve an excellent history matching for the lithofacies modelling and the petrophysical properties for the Abu Madi fluvial sandstones in Baltim field and surroundings.