1. Introduction

Figure 1. (a) Location map of the Ras Ghara oil field area in the southern Gulf of Suez, modified from EGPC 1996. (b) Locations of the available boreholes and 2D seismic lines used in this study. The black line refers to the direction of the stratigraphic correlation in Figure 8. The blue lines refer to the used seismic sections (GS 13-83 and FJ 88-05) shown in Figure 9.

Figure 1. (a) Location map of the Ras Ghara oil field area in the southern Gulf of Suez, modified from EGPC 1996. (b) Locations of the available boreholes and 2D seismic lines used in this study. The black line refers to the direction of the stratigraphic correlation in Figure 8. The blue lines refer to the used seismic sections (GS 13-83 and FJ 88-05) shown in Figure 9.

2. Tectonic and Stratigraphic Settings

Figure 2. General stratigraphic column and major petroleum system of the Ras Ghara area in the southern Gulf of Suez, Egypt (modified and after [5,29,32].

Figure 2. General stratigraphic column and major petroleum system of the Ras Ghara area in the southern Gulf of Suez, Egypt (modified and after [5,29,32].

Figure 3. Structural setting of the Ras Ghara and adjacent areas in the southern Gulf of Suez after 32 1996. (a) Structural map with contours and faults on top of the Kareem Formation, with showing well locations. (b) Structural profile showing the major troughs, structural trends, and stratigraphic setting with well locations. (c) Diagrammatic sections of the hydrocarbon-bearing horst complex systems.

Figure 3. Structural setting of the Ras Ghara and adjacent areas in the southern Gulf of Suez after 32 1996. (a) Structural map with contours and faults on top of the Kareem Formation, with showing well locations. (b) Structural profile showing the major troughs, structural trends, and stratigraphic setting with well locations. (c) Diagrammatic sections of the hydrocarbon-bearing horst complex systems.

3. Data and Methods

Figure 4. Workflow highlighting various steps and methods employed in this study for reservoir characterization and prospect assessment of the Ras Ghara oil field, Southern Gulf of Suez, Egypt.

Figure 4. Workflow highlighting various steps and methods employed in this study for reservoir characterization and prospect assessment of the Ras Ghara oil field, Southern Gulf of Suez, Egypt.

4. Results and Discussion

4.1. Well-log analysis

An extensive examination of Ras Ghara well data was carried, focusing specifically on eight wells situated within the selected study region (as seen in Figure 1b). The primary objective of this study was to evaluate the petrophysical properties the Miocene Kareem and Rudeis reservoir formations. The reservoirs’ formation water resistivity (Rw) ranged from 0.008 to 0.103 ohm.m. Following that, the specified cutoff threshold values, which include an effective porosity of 10%, a water saturation up to 50%, and a shale content less than 35%, for the southern Gulf of Suez Basin were applied,

The procedure involves identifying and analyzing the individual components and characteristics of the geological lithological members of a reservoir formation. Neutron-porosity and density cross plots are frequently used to identify lithological characteristics. Geoscientists use neutron-porosity density cross plots to differentiate between various lithologies in the reservoir, determine the porosity of the reservoir rocks, and assist in evaluating the fluid saturation within the reservoir [61].

From the Neutron-porosity\Density cross-plots in the GMA-1 well (Figure 5a) of the Kareem reservoir in the study area, it is observed that a dense cluster of points are scattered close (shale and anhydrite effects) to the clean sandstone line, especially for Neutron porosity greater than 20%. Less than about 40% of the points coincide with or in the vicinity of the limestone\dolomite trend with tight cluster that is possibly low porosity anhydrite. Effective porosity is ranging from 16 to 27% in GMA-1 well and density is ranging from 2.1 to 2.7 g/cm3, this indicates that the reservoir lithology is mainly composed of about sandstone and shale with minor intercalation of limestone, dolomite,and evaporites. Dolomitization reflects porosity enhancing diagenetic history of the carbonate reservoir of this field.

Figure 5. Lithological identification Neutron-density cross-plots for the Kareem and Rudeis reservoirs in the GMA-1 well. (a) Kareem Formation, (b) Rudeis Formation.

Figure 5. Lithological identification Neutron-density cross-plots for the Kareem and Rudeis reservoirs in the GMA-1 well. (a) Kareem Formation, (b) Rudeis Formation.

The Neutron-porosity\Density cross-plots in the GMA-1 well (Figure 5b) of the Rudeis reservoir in the study area, it is observed that most of the plotted points are scattered close to the limestone line, especially for Neutron porosity greater than 20%. Effective porosity is ranging from 7 to 29% in GMA-1 well and density is ranging from 2.1 to 2.7 g/cm3, this indicates that the reservoir lithology is mainly composed of about 85% limestone and shale with minor intercalation of sandstone.

An M-N cross-plot [61], which is independent of primary (intercrystaline and intergranular) porosity and commonly referred to as Pickett plots, is extensively utilized in the field of petrophysics for the purpose of identifying the matrix mineralogy (lithology) of reservoir rocks.

The M versus N in the GM-4 well in Ras Ghara oil field (Figure 6), reflects a dominant lithotypes of limestone, sandstone, and shale with considerable proportion of anhydrite. Most data points are distributed around the region between the calcite and dolomite regions, with a few data points in proximity to the quartz region. The observed geological characteristics may suggest the existence of limestone reservoirs, as well as the presence of shale formations interspersed with occasional sandstone layers. The upward scattering of certain spots is attributed to secondary porosity. Computed Gamma ray color scale is used to evaluate the consistency of clustering from one cross-plot to another.

Figure 6. M/N cross plot in GM-4 well reflects a dominant lithotypes in the Kareem and Rudeis formations.

Figure 6. M/N cross plot in GM-4 well reflects a dominant lithotypes in the Kareem and Rudeis formations.

Following the determination of the rock facies type and the calculation of petrophysical properties within the reservoir, the findings were vertically depicted to showcase the vertical variations in both the rock facies and the properties across the study wells located in the Ras Ghara oil field. The depths observed in the study wells varied from, 1501-1590 m in GL-1 well, 1992-2014 m in GMA-1 well, 2192-2466 m in GM4 well, 2278-2334 m in GM4 ST2 well, 2183-2264 m in GM-1 well, 2168-2250 m in GMD-1 well, and 2350-2400 m in GMD-2 well for Kareem and Rudeis formations respectively, while the Rudeis Formation reach its formation top at 2172 m in SINAI-6 well. Regarding the petrophysical quality of the reservoir layer, the Kareem reservoir properties can be summarized as follows: The net pay thickness of the reservoir layer varied from 3 m in GMA-1 and GMD-2 wells to 48 m in GM-1 well. Additionally, the effective porosity values ranged from 14% in GL-1 well to 33% in GMD-2 well. The shale content within the research region exhibited an approximate value of 23% in the GM4 ST2 well. The water saturation levels in GMD-1 and GMA-1 wells varied between 23% and 65%, respectively. Consequently, the saturation percentage of hydrocarbons might potentially exceed 77%, as seen in Table 1.

The Rudeis reservoir properties can be summarized as follows: The net pay thickness of the reservoir layer varied from 4 m in GMD-1 and GL-1 wells to 58 m in GMD-2 well. Additionally, the effective porosity values ranged from 15% in GM4 ST2 and GMA-1 well to 25% in GMD-1 well. The shale content within the research region exhibited an approximate value of 26% in the GM4 ST2 well. The water saturation levels in SINAI-6 and GMA-1 wells varied between 16% and 60%, respectively. Consequently, the saturation percentage of hydrocarbons might potentially exceed 84%, as seen in >Table 1.

Figure 7. depicts the Computer Processed Interpretation (CPI) study conducted on the GM-1, GL-1, and GM-4 wells, serving as an instructive example. This study covers ten discrete pathways, commencing with the depth, then gamma ray pathway and ends with the lithofacies pathway. The results of this investigation suggest that the rock facies identified in the Kareem and Rudeis formations consist predominantly of limestone and sandstone, with occasional instances of shale interbeds. The presence of vertical facies variation is apparent, as indicated by the prevalence of limestone facies in the top and middle zones. This transition is accompanied by the emergence of sandstone facies interspersed with shale.

Figure 7. The vertical distribution of well-logs, petrophysical parameters, and lithofacies, ac-quired from the Kareem and Rudeis formations using the CPI plots, (a) GM-1 well, (b) GL-1 well, and (c) GM-4 well. .

Figure 7. The vertical distribution of well-logs, petrophysical parameters, and lithofacies, ac-quired from the Kareem and Rudeis formations using the CPI plots, (a) GM-1 well, (b) GL-1 well, and (c) GM-4 well. .

4.2. Stratigraphic Interpretation

The stratigraphic correlation approach is a method employed to establish a connection between distinct rock layers or strata in various geographical regions. The objective is to ascertain whether the strata in one region are comparable or analogous to those in another region, and if so, to establish their chronological order and depositional chronicles in relation to each other.

The initial stage in constructing a three-dimensional representation of oil or gas reservoirs involves ascertaining the stratigraphic placement of the designated region in order to comprehend the prevailing stratigraphic sequence and the interrelationships among the various layers. The identification of unconformity surfaces is crucial for understanding the genesis of significant stratigraphic petroleum reserves, thereby necessitating precise indication of their existence or absence.

The focus of this study is to the deposit Miocene, with particular emphasis on the Kareem and Rudeis formations. This specific formations serves as the primary reservoir in the majority of fields located in the southern Gulf of Suez of Egypt [4,62,63]. The substantial thickness and unique compositional characteristics of this layer contribute to its significance in hydrocarbon exploration.

In order to facilitate a comparative analysis of the Kareem and Rudeis formations in the wells under investigation (namely, GL-1, GM-A1, GM-A2, SINAI-6, GM-4-ST2, GM-4, GM-1, GM-D2, and GM-D1), a vertical correlation section was created. This correlation was placed in a left-to-right sequence, with GL-1 being the leftmost well and GM-D1

being the rightmost well. The goal of this arrangement was to enable a comprehensive examination and comparison of the Kareem and Rudeis formations (Figure 8). The Rudeis Formation is stratigraphically overlain by the Nukhul Formation, forming an unconformity connection. It is distinguished by its considerable thickness, primarily focused in the northeastern direction and in the central part of the research region. The thickness steadily diminishes in the southwest direction. The correlation clearly indicates that the GM-A2 well has the lowest thickness of the Rudeis Formation.

Figure 8. Stratigraphic correlation section for Kareem and Rudeis formations in through the selected wells in the Ras Ghara oil field, southern Gulf of Suez, Egypt.

Figure 8. Stratigraphic correlation section for Kareem and Rudeis formations in through the selected wells in the Ras Ghara oil field, southern Gulf of Suez, Egypt.

The Kareem Formation, located atop the Rudeis Formation, has a consistent and uniform thickness across the research region. However, it is worth mentioning that there is a significant rise in thickness towards the southwest direction of the Ras Ghara oil field in the southern Gulf of Suez. The minimum thickness value is located in GM-4-ST2 well. The Kareem Formation is positioned above the belayim Formation in a conformable manner.

4.3. Structural Setting and Seismic Interpretation

The Ras Ghara oil field, as described in the EGPC, 1994, is characterized by a structural setting dominated by normal faults. These faults exhibit trends in the northwest-southeast and northeast-southwest directions, giving rise to a series of horst (uplifted blocks), graben (down-dropped blocks), and step-fault structures. These faulted blocks extend from the Miocene epoch and continue into the post-Miocene sedimentary layers. The primary fault blocks have played a crucial role in shaping the Central and Nurit troughs (Figure 3), as well as the horst complexes within the field. The troughs are confined by a principal fault along their southern margin, while a secondary fault trending in the 'B' direction delineates their western boundary. These faulted structures have emerged as prime targets for hydrocarbon exploration and production. As depicted in (Figure 3), the prominent structural features of the Miocene reservoirs within the Ras Ghara oil field can be explained as follows: The horst complexes exhibit lower Miocene clastic reservoirs, which are overlain by an upper Miocene evaporite plateau. This depositional sequence is predominantly present on the southwest-facing slopes of the pre-Miocene horst blocks.

In summary, the Ras Ghara oil field showcases a complex structural framework characterized by a network of normal faults with distinct orientations. These faulted blocks have given rise to horst, graben, and step-fault structures, contributing to the formation of the Central and Nurit troughs and horst complexes. The faulted structures represent key targets for hydrocarbon exploration, with the Miocene reservoirs displaying distinct characteristics such as lower Miocene clastic reservoirs overlain by an upper Miocene evaporite plateau. The interpretation of seismic data plays a crucial role in the field of petroleum exploration as it entails the examination and analysis of seismic data to extract valuable information about the properties and arrangements of subsurface formations.

Seismic horizons are identifiable geological boundaries or surfaces in the subsurface that are used for interpretation in horizon and fault analysis. To understand these horizons, one must first determine their locations within the seismic data and then track their paths throughout the seismic volume. The main goal of fault interpretation is to identify and characterize fault zones that may affect the spatial distribution of underlying geological formations, as stated by [64]. Velocity Modelling and Depth Conversion are essential for estimating the distribution of subsurface velocity based on seismic data [65]. Well log data integration is commonly used to align and verify the seismic interpretation, as stated by [8,64].

The investigation of subsurface conditions, encompassing both structural and stratigraphic characteristics, involved the interpretation of nineteen seismic reflection profiles (Figure 1b). Two seismic lines, GS 13-83 and FJ 88-05, depicted in Figure 9, exhibited a NE-SW orientation, closely intersecting the GL-1, GM-A2, GM-A1, SINAI-6, and GM-4 ST2 wells situated in the central region of the study area (Figure 9b). A comprehensive analysis was conducted on the Zeit, South Gharib, Belayim, Kareem, and Rudeis formations to discern their surface attributes and discern any fault influences.

The findings indicate the presence of multiple normal faults, resulting in the formation of horst, graben, and step faults within the Ras Ghara oil field. Furthermore, the Kareem and Rudeis formations were successfully penetrated by the examined wells, as depicted in the figure. Additionally, the figure illustrates the significant influence of five major faults (F1, F2, F6, F7, and F8) and four minor faults (F3-F5 and F9) on the study area.

To obtain a visual representation of the subsurface structure in terms of its depth, it is essential to create a map that shows the structure at different depths. Geoscientists can enhance their comprehension of the complex geological framework under the surface by constructing a detailed depth structure map. The location and shape of geological features such as faults, folds, and other structural aspects are disclosed, as stated by [66].

Figure 9. NE-SW interpreted seismic sections for the Miocene stratigraphic units in the central part of the Ras Ghara oil field: (a) seismic well tie using a check-shot in the GL-1 well; (b) base map showing the location of the interpreted seismic sections and structure features; (c) GS 13-83 and (d) FJ 88-05.

Figure 9. NE-SW interpreted seismic sections for the Miocene stratigraphic units in the central part of the Ras Ghara oil field: (a) seismic well tie using a check-shot in the GL-1 well; (b) base map showing the location of the interpreted seismic sections and structure features; (c) GS 13-83 and (d) FJ 88-05.

The Kareem and Rudeis formations are the primary reservoir in the Ras Ghara area, as seen by the depth structure contour map on top of Kareem and Rudeis reservoirs (Figure 10). There are a total of nine faults in these reservoirs, with some being quite major and others quite minor. The depth might be range between 1501m and 2350 m for Kareem Formation, while the Rudeis Formation range between 1590m and 2466m. All faults run northwest to southeast. These groups of Normal faults coalesce into horst, graben, and step fault complexes. All wells were conducted within the upper thrown side of the interpreted faults that impact the Miocene formations in the southern Gulf of Suez. These fault closures exhibit favorable characteristics, including well-defined sealing areas, which create optimal conditions for the accumulation of oil reserves. Both formations are distributed from shallow depths in the NE part to deeper depths in the SW part, which are vertically displaced by faulted graben and horst blocks.

Figure 10. The depth structure contour maps on the top of (a) Kareem Formation and (b) Rudeis Formation in the Ras Ghara oil field.

Figure 10. The depth structure contour maps on the top of (a) Kareem Formation and (b) Rudeis Formation in the Ras Ghara oil field.

4.4. Three Dimentional Structural Model

After the interpretation of seismic data and the generation of structural maps, the subsequent step involved constructing a comprehensive structural model for the Ras Ghara area. This model was developed in three key stages. Initially, the focus was on characterizing the fault system impacting the target formations under investigation. Subsequently, a pillar gridding technique was employed to establish a grid framework for the model. Finally, the horizons were delineated and categorized, enabling their subdivision into layers to facilitate the identification of structural effects, variations in rock facies, and changes in the petrophysical properties of the Kareem and Rudeis reservoirs (Figure 11). This approach allowed for a detailed understanding of the subsurface architecture and provided valuable insights for reservoir characterization and analysis in the designated region.

Figure 11. illustrates the primary steps involved in creating a three-dimensional structural model in the Ras Ghara oil field.

Figure 11. illustrates the primary steps involved in creating a three-dimensional structural model in the Ras Ghara oil field.

Figure 12 showcases a vertical structure cross-section aligned in the northeast-southwest direction, providing a visual representation of the influence of structures on the Kareem and Rudeis formations within the Ras Ghara oil field in the southern Gulf of Suez Basin. Analysis of this cross-section unveiled the presence of nine recurrent normal faults in the region, characterized by northwest-southeast and northeast-southwest orientations. These faults interact with each other, leading to the formation of geological features such as horst, graben, and step fault blocks. Notably, the study wells were strategically drilled near the upper displacement zones of faults 1, 3, 4, and 5. These findings contribute valuable insights into the structural dynamics and reservoir potential of the studied area, aiding in the optimization of exploration and production strategies.

Figure 12. (a) 3D subsurface model of the Belayim, Kareem, and Rudeis formations in the Ras Ghara oil field, showing faulted blocks with horst and graben structures. (b) A NE-SW cross-section of 3D model with showing three formations, faults F1–F9 and well locations.

Figure 12. (a) 3D subsurface model of the Belayim, Kareem, and Rudeis formations in the Ras Ghara oil field, showing faulted blocks with horst and graben structures. (b) A NE-SW cross-section of 3D model with showing three formations, faults F1–F9 and well locations.

4.5. Three Dimentional Property Model

The 3D static property model acts as a platform for integrating diverse reservoir data, including geological, petrophysical, and geophysical information [7,8,48]. The 3D static property model (facies and petrophysical) provides a detailed representation of the spatial distribution and variability of reservoir properties, such as porosity, permeability, and fluid saturation. This enables a better understanding of reservoir heterogeneity, identifying areas of high and low productivity, and guiding well placement and reservoir management strategies. By integrating various data sources, including well logs, and seismic data, the 3D static property model provides a comprehensive characterization of the reservoir. It helps identify geological features, such as faults, fractures, and stratigraphic variations, which influence fluid flow behavior and impact reservoir performance.

Upscaling petrophysical features of reservoir formations is crucial due to its impact on computing efficiency, model representation, and reservoir management. When working on extensive reservoir simulations or field development plans, the complex calculations required for high-resolution petrophysical data obtained from well logs or core samples can be computationally challenging. Hence, upscaling enables a more effective depiction of the reservoir properties while maintaining the essential features that impact fluid flow behavior.

Figure 13 illustrates the vertical changes in the rock types and physical properties of the reservoir layer, along with the efforts made to scale up these important elements. The diagram displays well differentiated geological facies consisting of limestone, shale, and sandstone. The Kareem Formation is distinguished by the prevalence of a prominent limestone facies accompanied by substantial quantities of sandstone facies, whereas the Rudeis Formation is distinguished by the occurrence of diverse facies including limestone, shale, and sandstone. The upper section of the Rudeis Formation is primarily composed of sandstone and shale, characterized by a rough texture. In contrast, the lower region of the reservoir exhibits a greater presence of limestone, which has a smoother appearance. Upon closer analysis, it becomes apparent that the prevailing rock types identified in the GL-1 well consist primarily of limestone, with some shale and a little amount of sandstone. Figure 13 vividly depicts the vertical variability seen in upscaled petrophysical parameters, including effective porosity, clay content, and degree of water saturation.

Figure 13. The vertical distribution of the upscaled facies, and petrophysical properties of Kareem and Rudeis formations in GL-1 well in the Ras Ghara oil field.

Figure 13. The vertical distribution of the upscaled facies, and petrophysical properties of Kareem and Rudeis formations in GL-1 well in the Ras Ghara oil field.

The cells intersected by drill holes must be assigned lithofacies and rock property values [67]. The subsurface structural and stratigraphic setting of the Kareem and Rudeis formations was applied to the property models. Lithofacies interpretation is based on well-log data, which differentiates the logarithm of each interpreted sediment surface according to the three major lithofacies: limestone sandstone, and shale (Figure 14). 3D static models for lithofacies were constructed based on sedimentary simulations of rock types. For this, the Kareem and Rudeis sections were divided into thirty and fifty layers respectively, to capture small-scale vertical non-uniformities in sufficient detail. Petrophysical features were utilized to create the 3D property models of effective porosity, shale content, and water saturation (Figure 14). The facies model suggests that the Kareem and Rudeis formations are composed primarily of limestone and sandstone, with some intercalated shale.

Figure 15 showcases the spatial distribution of rock facies within the Kareem Formation, encompassing limestone, shale, and sandstone, along with key reservoir properties such as effective porosity, shale content, and water saturation. The dominance of limestone facies is observed in the research area, primarily concentrated in the northeastern and southwestern directions. A progressive lateral fading is seen, followed by the occurrence of sandstone and shale facies, mainly focused on the central region. Moreover, a significant increase in effective porosity values is noted in both the central and northeastern directions. The shale content exhibits an upward trend towards the northwest, while decreasing towards the northeast. Water saturation demonstrates a decline towards the center and a gradual increase in both the northeast and southwest directions of the research region. These findings contribute to a comprehensive understanding of the reservoir's geological characteristics and have profound implications for optimized reservoir modeling and hydrocarbon exploration strategies.

Figure 16 depicts the spatial configuration of rock facies in the Rudeis Formation, including limestone, shale, and sandstone. In addition to the distribution map of effective porosity, the reservoir's shale composition and water saturation are also considered. The spatial distribution map of rock facies in the Rudeis Formation highlights the prevalence of limestone facies, primarily concentrated in the southwestern direction. The facies transition gradually to sandstone facies in the central region of the study area, before reappearing in the northeastern direction. Notably, all sandstone facies are concentrated in the central part of the study area. Additionally, there is a presence of shale facies in minimal quantities, primarily concentrated in the far northeastern region of the study area.

The effective porosity values exhibit an upward trend in both the central and southwestern regions, indicating increased pore space availability. Conversely, the clay content values demonstrate a decreasing pattern in the southwestern and central parts, as well as in the northeastern direction of the Ras Jara area. Notably, the water content values exhibit an ascending trend in the southwest direction, while experiencing a decline in the northeast and central regions of the study area. These observations provide crucial insights into the reservoir's fluid behavior and have significant implications for optimizing hydrocarbon recovery strategies and reservoir management in the Ras Ghara area. The observed sequence of rock facies, characterized by a transition from limestone to shale and ultimately sand, implies a plausible north-eastward direction for the beach (platform), while concurrently suggesting a south-westward orientation for the basin development. These findings provide crucial insights into the paleogeographic evolution of the region, offering valuable information on the depositional dynamics and contributing to a comprehensive understanding of the geological history. This knowledge is of paramount importance for accurate reservoir characterization and optimizing hydrocarbon exploration strategies, ultimately enhancing the success rates and economic viability of petroleum operations in the investigated area. The spatial and vertical heterogeneity in lithofacies and petrophysical properties within the Gulf of Suez rift basin are predominantly influenced by the tectonic and structural framework of the region. The primary structural traps in this basin are closely associated with faulted blocks, which play a pivotal role in controlling the distribution and accumulation of hydrocarbons. Additionally, the fault planes serve as important conduits for hydrocarbon migration.

To summarize, the 3D static property model is essential in evaluating reservoirs as it offers a thorough and precise depiction of reservoir features. It facilitates the process of understanding and describing reservoir properties, modeling and analyzing different scenarios, assessing uncertainties, and optimizing techniques to enhance oil recovery. Ultimately, it supports making well-informed decisions and implementing better reservoir management practices.

Figure 14. 3D static reservoir models across the Ras Ghara oil Field. (a) facies model, (b) effective porosity model, (c) shale volume model, and (d) water saturation model.

Figure 14. 3D static reservoir models across the Ras Ghara oil Field. (a) facies model, (b) effective porosity model, (c) shale volume model, and (d) water saturation model.

Figure 15. The selected productive layer in the Kareem Formation, Ras Ghara oil field, (a) facies distribution (b) effective porosity, (c) shale content, and (d) water saturation.

Figure 15. The selected productive layer in the Kareem Formation, Ras Ghara oil field, (a) facies distribution (b) effective porosity, (c) shale content, and (d) water saturation.

Figure 16. The selected productive layer in the Rudeis Formation, Ras Ghara oil field, (a) facies distribution (b) effective porosity, (c) shale content, and (d) water saturation.

Figure 16. The selected productive layer in the Rudeis Formation, Ras Ghara oil field, (a) facies distribution (b) effective porosity, (c) shale content, and (d) water saturation.

4.6. New Prospect and Reserve Estimation

Multiple sources [2,7,8,48,68,69] emphasize the utilization of well log and seismic data for prospect detection, which involves identifying areas with favorable geological and economic conditions for exploratory drilling and assessing reservoir quality and hydrocarbon reserves. In the case of the Kareem and Rudeis formations, these formations exhibit relatively high hydrocarbon saturation, reaching up to 77% and 84%, respectively, accompanied by an effective porosity range of 14% to 33%. The sandstone reservoirs within these formations have demonstrated associations with source rocks and seals.

By integrating models of lithofacies and petrophysical properties, we conducted an evaluation of limestone and sandstone distribution, revealing favorable reservoir quality within traps formed by faulted structures. These faulted structures serve as the primary targets in our search for new prospects in the Ras Ghara oil production area. Through our analysis, we have identified a target area as a new prospect, specifically focusing on two prospect areas located on the upthrown side of fault F1 and F3. Depth contour maps depicting the top of the Kareem and Rudeis reservoirs exhibit a three-way closure, indicating potential for reservoir accumulation (Figure 10). Furthermore, constructed cross-sections reveal that the predominant facies within these prospect areas are limestone and sandstones. The effective porosity ranges from 14% to 33%, while water saturation ranges from 16% to 65%, and hydrocarbon saturation ranges from 35% to 84% (Figure 15 and Figure 16). These findings provide valuable insights into the reservoir characteristics and aid in identifying potential drilling targets within the newly identified prospect area.

In Figure 17, a series of vertical sections are presented, oriented in the northeast-southwest direction, aiming to showcase the variations in rock facies and petrophysical parameters within the Kareem and Rudeis reservoirs. As discussed earlier, these sections serve to identify potential areas suitable for implementing a development plan. Notably, areas located along the upper throw of normal faults No. 1 and 3 have been recognized as favorable locations, exhibiting a promising three-dimensional closure zone and demonstrating positive petrophysical properties within the reservoir.

These noteworthy areas are delineated by a dashed red line, indicating their significance for future exploration and production activities. This information holds considerable importance for reservoir characterization and decision-making processes, contributing to the optimization of hydrocarbon recovery and the successful implementation of development strategies.

The following equation was utilized to compute hydrocarbon volumes: (Cannon, 2018);

HCIIP= (GRV*ϕ NTG*(1-S_w)) /FVF (1)

where HCIIP is the hydrocarbons initially in place, GRV is the gross rock volume, ϕ is the porosity, NTG is the net/gross reservoir ratio, Sw is the water saturation, and FVF is the formation volume factor.

The original oil-in-place (OOIP) of the two new prospects was determined using the HCIIP volume calculations, as shown in Table 2. This study provides estimates for the original oil in place (OOIP) in the Kareem Formation, which are approximately 2,002,404 STB and 1,175,580 STB. The oil reserves in this formation are estimated to be 600,721 STB and 352,674 STB. In the Rudeis Formation, the estimated OOIP is 6,302,916 STB and 2,841,894 STB, with oil reserves of about 1,890,875 STB and 852,568 STB for the first and second prospects respectively. The evaluation of oil reserves and the potential opportunities for developments can directly influence the levels of hydrocarbon output at the Ras Ghara oil field.

Figure 17. NE-SW trending cross-section profiles of 3D property models (a) lithofacies distribution. (b) effective porosity. (c) shale content. (d) water saturation of the Kareem and Rudeis formations in the Ras Ghara oil field; the dotted line refers to the new prospect wells.

Figure 17. NE-SW trending cross-section profiles of 3D property models (a) lithofacies distribution. (b) effective porosity. (c) shale content. (d) water saturation of the Kareem and Rudeis formations in the Ras Ghara oil field; the dotted line refers to the new prospect wells.

5. Coclusions

• This study presents an insightful understanding of the reservoir attributes of the Kareem and Rudeis formations. The petrophysical properties, lithology, faulted structures, and hydrocarbon distribution through a three-dimensional static model, has been established for Ras Ghara Field, southern Gulf of Suez.
• The established favorable hydrocarbon accumulations in fault horst blocks of Kareem and Rudies in Ras Ghara field are interpretable on 2D seismic reflection data despite structural imaging and seismic signal-to-noise issues.
• The petrophysical investigations determined that the net pay thicknesses varied between 3 m and 48 m in the Kareem reservoirs, and between 4 m and 58 m in the Rudeis reservoirs. The porosity range is 14–33% and 15–25%, respectively, while the hydrocarbon saturation range is 35–77% and 40–84%, respectively.
• The distribution pattern of the limestone and sandstone reservoir zone within the Ras Ghara oil field is primarily focused in the northeastern, southwestern, and central regions, displaying a discernible eastward migration from the Rudeis to Kareem formations. In essence, the central region stands out as the predominant location for the limestone and sandstone facies, distinguished by higher effective porosity and lower water saturation. This spatial arrangement of reservoir lithologies holds significant implications for high-impact journals, as it highlights the key areas of concentration and migration patterns of hydrocarbon-bearing formations in the Ras Ghara oil field.
• The estimated original oil in place (OOIP) within the reservoir formations of the Ras Ghara oil field indicates substantial quantities of oil, with the Kareem Formation holding 2,002,404 STB and 1,175,580 STB of oil for the proposed two new prospects, respectively. Additionally, the Rudeis Formation contains a noteworthy 6,302,916 STB and 2,841,894 STB, respectively.

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