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Abstract The Nile Delta, North Africa’s leading gas-producing region, was the focus of this study aimed at delineating gas-bearing sandstone reservoirs from the Pleistocene to Pliocene formations using a combination of pre-stack inversion and rock physics analysis. This research employed seismic inversion techniques, including full-angle stack seismic volumes, well logs, and 3-D with rock physics modeling to refine volumes of P-wave velocity (Vp), S-wave velocity (Vs), and density. Traditional seismic attributes, such as far amplitude, proved insufficient for confirming gas presence, highlighting partial angle stacks, integrated the need for advanced methods. Extended Elastic Impedance (EEI) analysis was used to predict fluids and identify lithology in clastic reservoir environments. The EEI approach facilitated the determination of optimal projection angles for key petrophysical properties such as porosity, shale volume, and water saturation. This method was applied to the middle Pliocene (Kafr El Sheikh Formation) and the Pleistocene (El Wastani Formation), revealing promising drilling sites. In the Kafr El Sheikh Formation, porosity ranged from 16 to 29%, shale volume from 21 to 40%, and hydrocarbon saturation from 25 to 90%. The study concludes that integrating pre-stack seismic inversion with EEI significantly enhances the likelihood of identifying gas-bearing sands while reducing exploration risks. The improved POS for the Pleistocene anomaly gas bearing sand (from 49 to 69%) and the middle Pliocene anomaly (from 46 to 66%) underscores the effectiveness of this approach in the Baltim Field, Offshore Nile Delta, and supports further drilling and development wells.

Abstract Given useful rock properties, gas sands generally appear as bright events on seismic data. Unfortunately, partially saturated gas sands tend to be of similar brightness to fully saturated gas sands so cannot be distinguished easily. Seismic inversion can sometimes help, given adequate seismic data and a robust understanding of rock physics. This study employs both post- and pre-stack seismic inversion techniques to estimate gas in place (OGIP) and evaluate reservoir properties within the Pleistocene gas sandstone reservoir of the Baltim Field, focusing specifically on the Kanaria prospect. The primary objectives are to estimate gas volumes, assess reservoir properties, and identify optimal well locations. Post-stack inversion is used to detect changes in acoustic impedance, which is essential for hydrocarbon identification, while pre-stack inversion provides insights into rock properties such as density. This approach helps to differentiate true gas sands from other geological features, like water layers or lithological anomalies, which can be misinterpreted as gas zones due to similar seismic responses or fluid variations. Although seismic indicators such as root mean square (RMS) amplitude and AVO analysis can suggest potential gas zones, they may also be affected by similar lithological effects, complicating accurate interpretation. The study confirms the presence of gas-bearing sands in the El Wastani and estimates an OGIP of approximately 0.4 Gm³ for well WB-1 and 6.6 Gm³ for well TERSA-1 ST. By providing detailed reservoir characterization and improving gas estimation accuracy, the findings support informed decision-making for drilling locations and enhance the potential for successful gas production in the Baltim Field.

AbstractThis study presents a comprehensive characterization of the Pliocene reservoir formation in the Temsah gas field, located 65 km NNW of Port Said in the northeastern Nile Delta Basin. The research integrates seismic data with well log analysis to enhance reservoir characterization. The Temsah gas field is distinguished by its intricate geological structure, featuring numerous normal faults oriented along northeast-southwest and northwest-southeast trends. The field’s stratigraphy is predominantly composed of sandstone and shale facies, which are considered highly prospective for hydrocarbon accumulation. A full geological field analysis was conducted to identify key prospects for enhancing productivity. To accurately delineate seismic features, data from four wells and twenty-nine 2D seismic lines were interpreted. Depth maps of the reservoir layers were constructed, highlighting critical transitions between sandstone and shale facies, which are pivotal for future exploration efforts. A detailed 3D static model was developed to illustrate the impact of lithological composition on reservoir characteristics, with a specific focus on the Upper Sand of Kafr El-Sheikh Formation. Petrophysical properties, including effective porosity (13–23%), shale content (7–31%), and water saturation (30–45%), were meticulously evaluated to inform the creation of a robust 3D property model. This model provides a detailed spatial distribution of rock facies and petrophysical parameters within the Temsah gas field. The integration of these studies identified two promising areas, with estimated original gas in place (OGIP) ranging from 2.86 to 4.04 stock cubic feet (SCF), indicating significant potential for field development and enhancement. [ABSTRACT FROM AUTHOR]

One of the main drilling challenges in the offshore deep-water Nile Delta is the overpressured Tertiary shales, which causes formation fluid influxes, kicks, and very narrow drilling window, thus contributes to non-productive times and enhanced drilling risk. Accurate understanding of pore pressure distribution is crucial for casing design, mud optimization and safe and successful drilling. This study presents first ever in-depth analysis of the pore pressure distribution within the 4500 m thick Oligocene-Pleistocene stratigraphy from the West Delta Deep Marine block in deep-water Nile Delta. Direct formation pressure measurements indicated around 0.06–0.1 PSI/ft (1.36–2.26 MPa/km) gas gradient in the Pliocene El Wastani and Kafr El Sheikh sandstone reservoirs, while the Miocene Qantara sandstones are water-bearing with a 0.42 PSI/ft (9.5 MPa/km) pressure gradient. Shale porosity distribution exhibited additional porosity retention within the montmorillonite and mixed clay-dominated Late Pliocene and deeper sediments and marks the onset of overpressure at the top Kafr El Sheikh Formation. Based on the loading trends and acoustic slowness-density relationship, we inferred compaction disequilibrium as the primary overpressure generating mechanism resulted from high sedimentation rate. Shale pore pressure was interpreted by utilizing wireline logs by utilizing compaction trendline-based approach and calibrated with drilling events and mudlog data. Qantara and Tineh formations are characterized by 0.75–0.77 PSI/ft (16.96–17.41 MPa/km) pore pressure gradient leaving a narrow drilling mud window of 1.7–2 PPG. Based on vertical effective stresses, two significant overpressure compartments were identified in the Late Pliocene and Early Miocene-Late Oligocene, which were separated by the Middle Miocene Sidi Salem Formation acting as a pressure seal. [ABSTRACT FROM AUTHOR]

The offshore part of the Nile Delta is considered one of the most prolific provinces for gas production and for future petroleum exploration. Amplitude Variation with Offset (AVO) analysis supported by composite logs considered as one of the best-advanced techniques enables the interpreter to understand the seismic data. It is used to generate a new view of the output results, especially for the identification of gas zones as gas channels by using pre-stack AVO attributes that based on the intercept product gradient (A*B) and the Scaled Poisson’s Ratio Change. Free gas, regardless of the percentage show obvious AVO anomaly. Well log data, including gamma-ray, resistivity, and Vp sonic logs are used in the seismic data to well tie and in the generation of the synthetic seismogram. Seismic data conditioning processes with check-shot correction is performed to improve the resolution of the reflection events and signal to noise ratio. AVO attributes technique, as a direct hydrocarbon indicator, including AVO gradient analysis and AVO crossplot separate the gas levels in the sand-shale sequences. The identified gas-bearing zones consistent with well log data responses. As the main conclusion, we show the visual evidence for the gas-bearing zones by interpreting different AVO responses due to the changes in fluid and rock types.

This study presents a comprehensive reservoir characterization of the channel sandstones of the Pliocene El Wastani Formation from the deepwater Scarab field, in Egypt. Routine core analysis, wireline logs, petrographic thin sections, X-ray diffraction, and drilling data were integrated to characterize the petrographical, petrophysical and geomechanical properties of the studied gas reservoirs to infer the implications for reservoir development. The petrographic analysis indicates fine to medium-grained glauconitic subfeldspathic wacke with dominantly primary intergranular porosity and minor secondary porosity contributed by feldspar dissolution. The reservoir facies exhibit pore-filling detrital clay (dominantly illite, smectite mixed-layer clay) along with minor carbonate and silica cementation. These reservoirs are megaporous and consist of an isotropic pore system, with 20–35 % porosity, 2400–3400 mD horizontal permeability, and 1300–2900 mD vertical permeability. Wireline log-based petrophysical assessments indicate excellent reservoir qualities with low shale volume (9–23%) and high hydrocarbon saturation of about 65–85%. Based on the geomechanical analysis, rock-mechanical properties, pore pressure, vertical stress, and minimum horizontal stress magnitudes were interpreted. The production and depletion-related risks were analyzed by utilizing geomechanical modeling which provided a quantitative assessment of drawdown and depletion limit to ensure sand-free hydrocarbon production without the risk of shear slippage on pre-existing weak planes. Considering the average unconfined compressive strength of 14 MPa, the Pliocene reservoir will require a 9.2 MPa depletion or 16.9 MPa drawdown to reach the onset of sanding, while the reservoir can be depleted to a pore pressure level of 4 MPa before it induces shear slippage on the optimally oriented fractures or fault planes. Inferences are drawn on reservoir quality, and reservoir development strategies are discussed accordingly. • The Pliocene gas reservoirs are composed of fine to medium-grained glauconitic subfeldspathic wacke. • Reservoirs exhibit dominantly primary intergranular porosity and minor secondary porosity contributed by feldspar dissolution. • The reservoirs are highly porous and permeable with high hydrocarbon saturation. • The El Wastani sandstone reservoirs have a gas gradient of 0.07–0.08 PSI/ft. • Solid production risk and depletion-induced reservoir stability are inferred from geomechanical characterization. [ABSTRACT FROM AUTHOR]

The eastern part of the offshore Nile Delta is one of Egypt's most productive gas provinces. This study utilizes well logs dataset and 2D seismic from Port Fouad marine (PFM) Field to investigate reservoir lithofacies, rock-types as well as the associated gas chimneys, pockmarks, bright anomalies of escaping fluids in the seafloor, and high-faulted zones caused by the chimney's developments. First, structural smoothing and median filters are used to improve the continuity of the stratigraphic horizons while preserving various geological structures, in order to pick all formation tops and structural faults. Afterwards, variance and energy attributes were computed and extracted for amplitude enhancement of various geobodies such as faults, gas chimneys, and bright reflectors. After that, petrophysical analyses revealed that the Upper Miocene Wakar Formation hosts scattered, thin gas pay zones (<10m) with low hydrocarbon saturation values (average S hc = 27.9%), high water saturation (average S w > 70%), and high shale volume (average V sh > 30%). These poor reservoir characteristics prevented accumulation of thick gas zones, thereby several gas escape features (e. vertical chimneys) are observed in the region. Finally, the estimated petrophysical parameter logs and the structure maps derived from seismic data are crucial components of the built 3D structural model. This model reveals the presence of four major normal faults (F1, F2, F3, and F4) oriented NW-SE and WNW-ESE, creating grabens and half grabens. These major faults (F1, F2, F3, and F4) are directly related to the inverted tectonics during the Cretaceous-Paleogene compression (Syrian Arc phase). A link between these structural patterns and gas escape zones is proposed, and the absence of good reservoir facies likely promoted an active phase of gas seepage in the study region. In addition, such gas escape chimneys can create catastrophic events on the seafloor and are considered direct evidence for the presence of gas generation and failure in accumulation. • Several subsurface gas seepage zones were reported offshore Nile Delta. • Subsurface imaging and seismic attributes configure the gas seepage regions. • Highly-faulted zones dissecting gas reservoirs are potential gas conduits. • Poor reservoir characteristics prevented gas accumulation at depth. • Gas escape provide direct evidence for gas generation and failure in accumulation. [ABSTRACT FROM AUTHOR]

Graphical abstract Highlights • Developing gas field in offshore Nile Delta. • Integrating seismic techniques for mapping gas sand bars. • Successfulness of coherency to map the faults, edges of sand bars, and contacts. • Investigating Class III gas sand reservoir using AVO attributes. Abstract The geometry and extension of Offshore Nile Delta sand bar complex deposited in a structurally controlled shallow marine basin is delineated by integrating seismic coherency and AVO attributes. Coherency is the imaging of discontinuities within the seismic data, where faults, sand bar boundaries and fluid contacts (GWC) were mapped, using an optimum analysis window of 40 × 40 × 64, and instantaneous amplitude of time slice image map at 1652 ms. AVO attributes are applied to reservoir sands of significant bright spot response. AVO attributes volumes, include the (A * B), (A + B), and (A − B) of the intercept and gradient, generated from near, mid, and far angle stacks. The seismic coherency volume delineated two major bounding faults of the reservoir, that converged at the western end of the field and open out to the east where, the reservoir is dip-closed. Four boundaries between five sand bars oriented in NW-SE direction are detected. GWC is delineated at the deepest part of the reservoir towards the southeastern part. AVO attributes indicated that the reservoir top is characterized by positive bright spots, negative Poisson's ratio, and increasing in the scaled S-reflectivity. Meanwhile, the bottom is characterized by bright spots, positive Poisson's ratio, and decreasing in the scaled S-reflectivity. AVO volumes were consistent, and show the typical response of Class III gas sands. Five high positive amplitude sand bars oriented NW-SE are confirmed. Three of them were successfully tested. The two prolific southern sand bars exhibit higher amplitude haven't been tested. [ABSTRACT FROM AUTHOR]

The offshore Nile Delta is a prominent petroleum province; nevertheless, previous research focused mainly on evaluation of Miocene–Pliocene possible source rocks because of lack of data. The current study is the first to evaluate organic geochemical features of the Upper Cretaceous–Pliocene sequence in the western offshore Nile Delta, applying TOC, Rock-Eval pyrolysis and GC-MS procedures for 137 ditch cuttings collected from three wells. The main objectives are to infer organic richness, type of kerogen, maturation, and depositional paleoenvironment of organic matter for these possible source intervals. The analysed rock samples generally display fair to good organic enrichment. Most of these samples are enriched in Type-III and Type-II/III kerogen, suggesting a high influx of terrigenous organic matter. However, Abu Madi, Appollonia, and Khoman formations contain Type-II oil-prone kerogen, reflecting more marine organic matter, whereas Kafr El Sheikh and El Wastani cuttings display the lowest TOC contents and are more enriched in non-generating inert organic matter. Biomarker ratios indicate that Kafr El Sheikh, Abu Madi, Qawasim, and Qantara formations are rich in Type-II/III kerogen (mixed organic matter) preserved under suboxic nearshore or lacustrine depositional environments. In contrast, Sidi Salem, Tineh, Appollonia, and Khoman formations contain abundant Type-II marine-algal organic matter deposited under anoxic marine depositional settings. Vitrinite reflectance data and biomarker ratios indicate immature to peak mature rock samples. The stable carbon isotopic composition of condensate oil samples suggests nonmarine waxy oils. Ratios of n -alkanes and isoprenoids for a condensate sample from the study area reveal no similarity with the Upper Cretaceous–Pliocene rock extracts. • Deeper pre-Oligocene cuttings from the offshore Nile Delta were examined for the first time. • TOC contents suggest fair to good organic enrichment. • Miocene and Pliocene intervals are rich in Type-III and Type-II/III kerogen. • Appollonia, Khoman, and some Abu Madi samples contain Type-II oil-prone kerogen. • Biomarkers suggest suboxic-anoxic depositional settings and more marine input for pre-Miocene samples. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Static reservoir modeling adequately and precisely defines the reservoir framework (geometry) and architecture (property). So as to substantially reduce the expected risk while defining the hydrocarbon-bearing reservoir boundaries, static geocellular model was constructed, in this study, to define lithology and fluid stochastic distribution, and volume of hydrocarbons as well, within the Late Pliocene hydrocarbon-bearing El Wastani Formation, (sandstone channel-1 and channel-2), in Scarab Field (offshore Nile Delta, Egypt). Twenty 2D seismic lines and well log data, of four wells, were used in this study. Stratigraphic, structural, facies, and petrophysical models were applied not only to estimate the volume of hydrocarbons within the reservoir but also to identify the best location for proposing new development wells that are of crucial value for oil industry development. In accordance with the constructed reservoir geocellular model, we found that the northwestern part of Scarab field is the best location for running further oilfield development plans. • Static (geometry and property) reservoir modeling for reducing risk of precisely identifying reservoir boundaries. • Applying kriging-based stochastic interpolation so as to spatially model rock property. • Estimating volume of hydrocarbon, gas initial in place (GIIP), in the study area. • Justifying running further oilfield development plans. [ABSTRACT FROM AUTHOR]