Introduction

Carbonate reservoirs are vital importance in the petroleum industry due to their huge reserves (Harbaugh 1967), about 60% of the world’s oil reserves are in carbonates (Singh and Joshi 2020). For several decades, petroleum fields have been producing resulting in new challenges and opportunities. The heterogeneity and tightness of carbonate reservoirs are the main challenges to sustaining production. The degree of complexity and heterogeneity changes over the field lifetime and the reservoir life cycle. Characterization of carbonate rocks is a key factor in unlocking its potential (Gao 2011; Gao et al. 2014; Beigi et al. 2017). Measuring the pore type has been attractive for petrophyscists and engineers (Gunter 1997, Lucia 1999; Lombard 2002, Dernaika et al. 2007). In addition to the differences in rock texture and fabric, which differentiate between skeletal and non-skeletal rocks, carbonate reservoirs consist of mixed lithologies, typical are wackestone, packstone, grainstone, dolostone, and crystalline carbonate based on the rock sedimentary texture (Dunham 1962; Embry and Klovan 1971). Carbonate rocks differ from sandstones; Carbonates are very susceptible to diagenesis, leaching and cementation, and dolomitization often occurs at a very early stage shortly after deposition (Choquette and Pray 1970). The progression of facies for a ramp depositional environment profile is systematically arranged based on topography and current energy (Lucia 1999). The common minerals are calcite, dolomite, siderite, anhydrite, gypsum, and shale minerals (Lucia 2007). The rock petrophysical properties and capillary pressure behavior are used to lump more than one microfacies to condition the geological model and facies association (Gomes et al. 2008). The existence of matrix primary porosity is an essential factor for charging the reservoir with hydrocarbon and increasing the burial depth shows progressive porosity reduction (Mazzullo 2004; Machel 2005). Carbonate rocks are generally compressible, and porosity decreases with increasing effective stress (Lucia 2007). Compaction during burial might transform a primarily excellent reservoir rock of high porosity into a poor non-reservoir rock (Gomes et al. 2008). The most useful division of pore types for petrophysical purposes was of pore space between grains or crystals called inter-particle porosity, and all other pore space called vuggy porosity (Lucia 1983, 1995). Carbonate rock classification based on the relationship between pore type, porosity, and permeability has been introduced by Ebanks et al. 1992; Amaefule et al. 1993; Gunter 1997, Pittman 1992; Tiab and Donaldson 2004 and Lonoy 2006. Radiansyah et al. 2014 described the pre-rift, syn-rift, post-rift and inversion in the south Sumatra Basin and its relationship with carbonate reservoirs. Egypt gives a lot of focus to carbonate reservoirs after a new offshore discovery in the east Mediterranean (ENI 2015). Carbonate rocks of the western desert are of big interest to many researchers, Helba et al. 2015; El-Bagoury 2015 and 2019; Abdelaziz et al. 2016; El-Bendary et al. 2016; Elmahdy et al. 2019 and Sen et al. 2021. This study emphasizes the major differences in rock texture and fabric, microfacies, rock mineralogy, petrophysical and geomechanical properties of carbonate succession in North Western Desert and AGB. Reservoir quality and connectivity of carbonate reservoirs in AGB are the significant challenges in developing reasonable in-place volumes (Kamel and Nagaty 2014); to unlock its potential and follow its entrapment system it is recommended to apply detailed lithological characterization (Elmahdy et al. 2020). Karstification is reported in the chalk of Khoman Fm. There are well-exposed caves and paleokarst topography developed within the Maastrichtian Khoman chalk outcrops of Bahariya Oasis in western desert (Tewksbury et al. 2017 and 2021).

The objectives of this study are: (i) a description and evaluation of carbonate reservoir rocks in the Abu Gharadig basin (AGB) and north Western Desert generally, (ii) a better understanding of the pore nature of the rocks, (iii) touching the reasons for higher reservoir quality and attractive microfacies, (iv) linking between core analysis and well logs to exhibit different rock types with similar petrophysical properties. (v) investigate the elastic properties of each rock type and intercorrelation with the Elan mineral model. This study investigates the carbonate rocks in AGB and gives more insights into the link between rock type, mineralogy, petrophysics, and elastic properties for future development and exploration plans.

Geologic setting

Egypt is located at the northeastern corner of the African plate and consists of the basement rocks of the East Sahara Craton and the Arabo-Nubian Shield over which a number of intracratonic basins have formed (Hegazy 1992). The Western Desert can be divided into a number of large scale structural provinces developed referentially along pre-existing lines of weaknesses in the basement and in response to lateral movements between Europe and Africa (Hegazy 1992). The sedimentary section overlying the igneous and metamorphic basement regionally thickens northwards reaching a thickness between 40,000 and 50,000 feet in Abu Gharadig Basin (AGB), thinning to 10,000 feet over the Ras Qattara Ridge, which marks the northern border of the basin (Fig. 1).

Fig. 1
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(Modified from Schlumberger 1995; Cohen 2013 and Bosworth et al. 2015)

Generalized stratigraphic column of western desert and studied carbonate reservoirs

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Most of the Western Desert hydrocarbons are concentrated in the northern part mainly over the Cretaceous and Jurassic reservoirs. Oil and gas discoveries started by 1966 in Alamein field from the lower Cretaceous dolomite pay zones, El-Razzak oil field produces from the Aptian clastic Alam El-Bueib and Abu Gharadig field produces oil from Cenomanian clastics of the upper Cretaceous sands (Schlumberger 1995). The exploration and development activities were heavily continued in the western desert to more than 40 fields by 1992, and 578 wells were drilled by the year 2000. By 2010, the total number of drilled wells in Western Desert had doubled 3 times in the fields of Khalda, Qarun and Badr el-Din petroleum companies (El Bagoury 2019). AGB is one of the large-scale provinces in the Western Desert, It’s about 330 km long and 50–75 km wide (Meshref 1990; Hegazy 1992; Schlumberger 1995; Dolson et al. 2000). The geology of AGB has been discussed in (Said 1962, 1990; El Ayouty 1990; Wahdan et al. 1996). The east-west trending Sharib-Sheiba high is a regional uplift that separates AGB from the coastal basins (Matruh, Shushan, Dahab- Mireir and Natrun Basins (Fig. 2). Some local highs as Kattania and Mubarak highs affected by the extensive compression northeast-southwest trending folds (Fig. 2), the major tectonic movements, which gave AGB its present shape, took place near the end of the late Cretaceous time (Abdel Aal and Moustafa 1988).

Fig. 2
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The main structural elements of the north Western Desert area (Bayoumi 1996)

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The AGB passes through four different stages, Jurassic rifting, Cretaceous rifting, Santonian Inversion (Late Cretaceous to Early Cenozoic) and Post Dabaa Normal faulting (late Cenozoic). The basin is bounded on the north by the Qattara high and to the south by the Sitra platform. The basin consists of several ENE elongated pull apart grabens formed in the early Cretaceous and most of AGB faults die out on the Apollonia Formation (Abdel Aal and Moustafa 1988; Bakry 1994, 2005; Bayoumi 1996; Ibrahim 2014).

Data and methodology

This study integrates the routine core analysis (RCA) of 301 core samples, petrographic thin sections, microfacies, and wireline logs of five wells located in different fields well distributed in the Egyptian Western Desert (Fig. 3). These various measurements were integrated to assess the petrophysical, petrographical, and geomechanical characteristics of carbonate reservoirs in the study area. The workflow started with core data domain (porosity, permeability, and thin sections) then log domain for calibration (well log characteristics, petrophysical and geochemical parameters) (Fig. 4). The integration between reservoir description, routine core analysis (RCA), and petrophysical rock type (PRT) in carbonate rocks was developed for middle east fields by Sudarsana et al. (2009), Hollis et al. (2010), Burchette (2012) and Radiansyah et al. (2014). Carbonate rocks of similar origin, pore types and petrophysical characteristics are grouped based on core data as the geological factors controlling the reservoir quality and microfacies are key pillars in estimating the rock dynamic behavior (Gomes et al. 2008).

Fig. 3
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Base map of well locations used in this study

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The core description of microfacies is integrated with porosity to identify the statistical ranges and the dominant pore type. The porosity and permeability of all samples were plotted in one plot to group and cluster rocks of similar relationship and origin. Integration of bore hole logs for all rock groups is crucial for better reservoir definitions in every rock group. Moreover, to differentiate between pure matrix properties and the other naturally enhanced non-matrix origin associated with vuggy and fractured pores detected from the RCA characterization. Petrographical investigations were used to describe the carbonate rock types and the major differences in pore system and mineral content characteristic of each type (group). The core data are integrated with logs to calibrate the uncored wells (Table 1).

Elan model is used to describe the common rock minerals found in carbonate rock groups. This model enhances the understanding of dolomitization processes by digitizing the dolomite to calcite ratio. The quantitative Elan model is computed by Techlog software using the Quanti-Elan module.

Fig. 4
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Workflow chart of the research methodology

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Fig. 5
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a Stylistic grainstone showing micro-fracture (mf) and isolated vugs (black arrows) the dark color, small crystal and lack of sharp edges indicate early dolomitization (Abdelaziz et al. 2016), b Grainstone with meso- to macro-pores of vuggy to touching vuggy porosity and planar large and bright well-developed crystals with sharp boundaries, c Mixed mud and grain supported packstone to wakestone showing benthic foraminifera (yellow arrows) with intergranular (pp) and intragranular porosity (red arrows) and micritic cement. d Mud dominated wakestone with planktonic foraminifera (f) showing microporosity of intergranular (pp) porosity and micritic cement

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Elan models have shown wide applications in segregation between pure shales and other clay minerals such as kaolinite, smectite and illite. The linear equations to the stated five logs easily classify the main lithologies (Calcite, Dolomite and shales). The inputs are gamma ray, density, neutron, sonic and photoelectric logs in addition to lithology description reports. The input parameters for each mineral were set up after a set of iterations to understand the mixed lithologies. The Input parameters of this model are summarized in (Table 2). The output minerals are calibrated with composite logs and petrography reports at different intervals to validate the model. Sonic and density logs have been used as an input to calculate dynamic rock-mechanical properties from well logs, Poisson’s ratio (ʋ), Young’s modulus (E) and uniaxial compressive strength Brittleness index (BI) was calculated Grieser and Bray’s (2007);

$$\:\text{B}\text{I}=\frac{1}{2}\:[\:\frac{\text{E}-{E}_{min\:}}{{E}_{max\:}-\:{E}_{min\:}}+\:\frac{{\upnu\:}-{{\upnu\:}}_{min\:}}{{{\upnu\:}}_{max\:}-\:{{\upnu\:}}_{min\:}}\:]$$
Table 1 Min and max values of Youngs modulus (E) and Poisson’s ratio (ʋ) have been used for brittleness index calculation
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The common impact of age and depth on rock properties is highlighted and integrated with core and log characteristics for better insights into the nature of carbonate succession. The logical integration between the geological, petrophysical and elastic properties of each defined rock group will transfer the best understanding for all AGB carbonate rocks based on pore type, microfacies, mineral content, log characteristics and geomechanical parameters.

Table 2 Summary of input parameters of Quanti-Elan model
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Results

Petrographical investigation

The studied intervals retain wide lithological variations. Therefore, some observations from the studied thin sections can be made. The recorded porosity types include intragranular, intergranular, moldic, vuggy, and fractured porosity (Fig. 4), indicating a good secondary porosity for hydrocarbon accumulation. Alamein and Masajid are the oldest, while Apollonia and Khoman formations are the youngest. Masajid reservoir is highly dolomitized carbonate, sometimes argillaceous in parts (Fig. 4-a). The grainstone is the common microfacies in this formation. The diagenetic effects generally reduce the formation porosity in Alamein and Masajid reservoirs; however, the permeability is largely controlled by the nature of the vugs and fracture/channel networks (Fig. 4-b). The origin and depositional environment of Alamein and Masajid formations are likely to be a restricted shallow marine low energy environment. Sometimes these carbonates are interrupted by high energy where microsparites and sparites are formed (Zein el-Din, Abul-Fetouh and Sadek 1982). Dolomitization is one of the early diagenesis and pore system controlling factors creating connected vugs (Hartmann and Beaumont 1999). The distribution of vugs is highly varied within the same reservoir as separate vugs can restrict the reservoir permeability while vugs and touching vugs increase the permeability to higher values. Calcite and dolomite are the most common minerals in the studied samples. Abu Roash carbonates are described as packstone and wackestone microfacies with primarily intra-granular porosity. Shallow marine benthic foraminifera is commonly observed in many samples (Fig. 4-c). Apollonia reservoir is described as chalky limestone lithology highly fossiliferous (planktonic foraminifera). The high matrix porosity can be explained by the presence of rich mud size in the Khoman and Apollonia reservoirs (Fig. 4-d). The presence of pore space within shells and peloids that make up the grains of carbonate sediments increases the porosity over what would be expected from intergranular porosity alone (Dunham 1962) (Fig. 4-c). Dissolution channels, fractures, and touching vugs increase the reservoir permeability to a higher range. The different microfacies were integrated with the porosity of samples to emphasize the intercorrelation between them. The mud-supported microfacies show a very high porosity while grain-supported microfacies show a different distribution of porosity generally less than 20% (Fig. 5). Grainstone porosity rangd from 5 to 15% and extended reservoir permeability is observed due to dissolution channels, fractures and touching vugs.

Fig. 6
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A series of histograms showing the difference in porosity of carbonate microfacies, and their vertical frequency; a Packstone, b Packstone to Grainstone, c Wackstone to Packstone, d Fossiliferous Wackestone, e Mudstone, and f the two main distributions of grain and mud supported facies

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Porosity and permeability grouping

The porosity and permeability of the studied formations showed different trends of increment. Several observations can be made on the permeability distribution plot, and the three characteristic regions or groups can be identified in the Porosity-Permeability plot (Fig. 6). In general, three main carbonate types can be observed; Type-I (Masajid and Alamein), Type-II (Abu Roash) and Type-III (Apollonia and Khoman). There is very low porosity and permeability (tight) representing mud stone and compacted grainstone from a non-reservoir carbonate type. Depth and age are increased towards type-I which means type-I is the deepest and the oldest. High matrix porosity is characteristic of carbonate rocks of type-III (shallowest). The studied samples showed a regular reduction in porosity with the increase of depth and age (Fig. 6). Porosity increased towards type-III and permeability increased towards type-I. Porosity decreases with the increasing of effective stress and overburden as compaction during burial transforms the rock porosity. The minimum porosity for carbonate of type-III was 18% meanwhile the maximum porosity of type-I was 17%. Therefore, it is crucial for correct reservoir quality prediction along the AGB to consider these porosity values. Vugs are reported in the core descriptions at various degrees throughout the Alamein and Masajid reservoirs which contribute as secondary porosity. Pore types and the main microfacies are plotted in Fig. 7).

Fig. 7
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Core porosity and permeability types for all carbonate reservoirs in northern Western Desert

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Fig. 8
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Main pore types characteristic microfacies and diagenetic processes

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Well log characteristics and Elan model

The well log response is characteristic for defined rock types explaining the rock lithology and properties. High neutron porosity and low bulk density are characteristic of type-III While, type-I is highly compacted showing high density and low neutron porosity. Type-II represents an intermediate log signature between the other two types (see Figs. 8 and 9). Limestone of highly argillaceous content is marked with relatively constant bulk density with a slight increase in neutron logs scattering to the right of the main trend line. The reduction in total porosity by pore-filling clay minerals was indicated by the gamma ray logs, mud logs and core photos. Elan model is targeting a summary of mineral components against the different carbonate rocks. A few bad hole flags due to washout are highlighted in yellow filling color in the caliper log (Fig. 9). Type-III description indicates milky white color, chalky limestone fine and microcrystalline shifting to lite grey if argillaceous, sometimes contains chert, moderately soft to soft. Shale intercalations are rare in this type, while it is common in the other rock types which suggests a common and uniform deposition in type-III. Type-II is described as argillaceous light grey and light brown color, glauconitic, cryptocrystalline to microcrystalline, dolomitic, and moderate hardness. Carbonate rocks mainly consist of a mixture of calcite, dolomite and shales as halite, gypsum and anhydrite are rarely observed in AGB reservoirs. Type-I is described as pale yellow, yellowish brown color, highly dolomitic, moderately hard to hard. Dolomite is common in type-II and type-I with greater relevance in type-II. Type-III is found to be free from dolomite. High concentration of kaolinite in some intervals, which increases the recorded gamma ray and density logs (Fig. 9). Kaolinite mineral is differentiated from other shale minerals with spectral gamma ray logs (uranium, thorium and potassium). Kaolinite is highlighted as light green filling in the interpreted mineralogy column. Summary of all types of carbonate and log response against every rock type (Table 3). There is a markable increase in PEF and background resistivity logs this variance can illustrate the differences in rock mineralogy specially calcite to dolomite ratio (Table 3).

Fig. 9
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a Neutron and density logs cross plot and interpreted carbonate types. b Transit time and density logs cross plot and interpreted carbonate types

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Fig. 10
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a Type-I carbonate rocks (low dolomite content). b Type-II carbonate rocks (high dolomite content). c Type-III chalky carbonate rocks (free of dolomite)

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Table 3 Summary of well log characteristics and petrophysical parameters of carbonate types
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Elastic properties

The wireline logs are used to calculate the rock mechanical properties. The average Poisson ratio (ʋ) rangs from 0.24 to 0.42 and Young’s modulus (E) is ranging between 4 GPa to 55 GPa. Poisson ratio (ʋ) is 0.29, 0.31 and 0.32 for type-III, type-II and type-I respectively. The average Young’s modulus (E) is 18, 32, and 46 GPa for type-III, type-II and type-I respectively (Fig. 10). The brittleness analysis indicates a brittleness index (BI) range between 0.22 and 0.82. The estimated geomechanical properties ʋ, E, BI and UCS are found to be increased from type-III to type-I. The type-I exhibits BI > 0.8 indicating a higher brittleness nature than type-II (0.65). Type-III introduces ductile rock behavior. The estimated rock mechanical properties and BI are plotted together to correlate the increase of brittleness index with the increase of depth and age (Fig. 10). UCS varies between 20 and 55 MPa (Fig. 10).

Fig. 11
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Elastic properties of the three carbonate types

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Discussion

Integrated rock and pore typing

One of the primary objectives of this study is to conclude the main geological and petrophysical differences in the overall carbonate succession of AGB and the north Western Desert. Five main microfacies were interpreted from petrographical investigation packstone, grainstone, compacted grainstone, fossiliferous wackestone and mudstone. Mudstone and compacted grainstone are considered as non-reservoir. Three different sets of carbonate rocks in AGB are considered good reservoirs. The depositional and diagenetic characteristics indicated vuggy and fracture porosity in carbonate rocks of type-I. This type is originally a grain supported matrix transformed by chemical \ mechanical dolomitization of calcite. It is found barren of fossils with some shale intercalations interrupting the carbonate feeds. Type-II is described as wackestone and packstone microfacies, which is in the middle quality between type-III and type-I. Type-II is characterized by intraparticle porosity and dolomitization. Type-III microfacies is interpreted as fossiliferous wackestone of mud supported origin. Foraminiferal contents in type-III are indicative for open marine setting. The geological microfacies is controlled by the changes in grain size, sorting and faunal content. The grain size of type-III and lack of shale intercalations refer to an open marine and lower shelf slop environment. This type of carbonate is mainly controlled by stratigraphy while lack of dolomitization may be subjected the depositional environment and low compaction effect. The origin of dolomitization might be controlled by structural factors near faults and folds by chemical reactions or stratigraphic origin. The geometry of enhanced rock quality and connectivity are controlled by dolomitization in some of the studied fields as Razzak and NEAG (type-I and type-II). The pore system was utilized as a significant rock typing tool to ensure consistent petrophysical properties for each rock type. Matrix density is generally increased from type-III to type-I as a function of depth and origin of carbonates. The calculated porosity from logs is found to decrease with depth. Dolomitization plays a significant role in controlling reservoir properties. General speaking porosity and permeability are reduced as a function of depth and age however in AGB, the higher permeabilities are concentrated in deeper zones of type-I as a function of secondary porosity associated with diagenetic processes producing vugs and macro-pores network. Type-II pore system is less complicated than type-I, its permeability in the range of mesopores affected by the common structural elements in the basin. Intragranular porosity, micro fractures and fissures characterize carbonate permeability of this type. Type-III shows limited connectivity however; its porosity is the highest. Permeability is less than 1 mD with common microporosity. Few nanoporosity core plugs were found, they have not been considered because of limited frequency and accuracy. The Elan study suggests different mineral contents and geologic signatures for the studied formations. There are strong correlations between the pore system and mineral content. The mineral characterization gives an indicative signature to the pore system network and porosity ranges of the three different rock types.

Fig. 12
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The relationship between calcite and porosity in the three carbonate types

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Fig. 13
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The relationship between dolomite and porosity in the three carbonate types

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Calcite and dolomite minerals exported from Elan model showed characteristic porosity trends for each carbonate type. Dolomite to calcite ratio is generally higher and uniform in type-II comparing to type-I, which suggests a different origin of dolomite (Figs. 11 and 12). High clay volumes regularly reduce the porosity for the three types meanwhile, a strong correlation has been observed between porosity and dolomite. The increase of dolomite enhances the porosity in type-I meanwhile in type-II porosity reduced in highly dolomitized parts. Dolomitization show an influence on the pore size which is observed in porosity trends.

Geological and geomechanical properties

The geomechanical properties (ʋ, E, BI and UCS) showed an efficient increase with depth and age. There are strong correlations between rock brittleness, pore system and mineral content characteristics for each rock type (Fig. 13). Young’s modulus showed a higher response characteristic to the geological setting than Poisson’s ratio, which showed a slight change (0.01–0.02). As a result, at a similar Poisson’s ratio, a lower Young’s modulus means an increase in the pore network (Fig. 13). The brittleness index (BI) and uniaxial strength (UCS) are higher in the bottom part and decrease towards the top part in the three types. Bed thickness does not affect the brittleness index with in AGB; it looks to be much correlated with depth more than thickness. In outcrops spacing between natural fractures (fracture spacing) decreases, as bed thickness becomes smaller, other things being equal (Mc Quillan, 1973), same in Kuh-E Asmari limestone (Iran), Woodford shale of Oklahoma and other reservoirs (Diliegros and Luz 2021). The relationship between brittleness index and bed thickness can be considered in type-I and type-II but not for type-III. The relationship between brittleness and dolomitization was consistent and very conclusive and characteristic for the carbonate rocks with variable extent (Fig. 14). Geological and geomechanical parameters are summarized in Table 4 (Fig. 15).

Fig. 14
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The relationship between Young’s modulus and porosity in the three carbonate types

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Fig. 15
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The relationship between dolomite and brittleness index in the three carbonate types

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Table 4 Summary of common geological and geomechanical parameters of carbonate types
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Conclusion

North Western Desert passes through different phases of deformation, extensional and compressional. This study proves the potential of carbonate reservoirs. The carbonate succession of AGB includes seven zones of carbonate rocks. Five of them were studied in detail in this research. Petrographical microfacies are; mudstone, wackestone, packstone, and grainstone. The rock porosity is reduced in deeper and older rocks however, vuggy and fracture permeability is characteristic for older rocks. The total porosity is reduced by 10 to 15% for every one kilometer of depth. Based on the type of matrix, reservoir mineralogy, rock properties, pore type, and elastic properties three main groups (types) were detected.

  1. 1.

    Type-I characterizes the deep and old rocks as Alamein and Masajid reservoirs, it’s mostly grainstone and packstone microfacies preserving grain-supported carbonate origin. Petrographic diagenetic features include micritization, cementation, compaction, dolomitization, and dissolution. Fracturing and stylolite diagenetic overprints are also common. Reservoir enhancement is observed in reservoir quality (porosity and permeability) due to dolomitization, dissolution vugs, and channel fracturing. This type shows additional permeability higher than matrix permeability primarily generated in rocks. Vugs and touching vugs increase the permeability however; the overall porosity is still low due to higher matrix density (> 2.77 gm/cm3). Dolomite percentage showed an increase with porosity in this carbonate type as dolomitization connects a higher number of pores.

  2. 2.

    Type II sowed intermediate reservoir quality between type I and type III. This type is generally packstone and wackestone microfacies, which is characteristic of the Abu Roash formation and its subdivisions. The common stratigraphic setting of this type is a shallow marine environment which is indicated by the relevance of benthic fauna. Primary porosity and intragranular porosity are dominant. The permeability of packstone is better than wackestone in most of the samples, the increase of grain size, energy, and dolomitization enhance the reservoir quality. Reservoir quality is enhanced by structure (compression and inversion) that connects a higher number of pores where the dolomitization takes place. Dolomite and dolomitic limestone is the lithology. Dolomite to calcite ratio is 60%. Dolomitization showed a negative impact on the porosity of this carbonate type.

  3. 3.

    Type III is mostly described as wackestone. The stratigraphy of this type is the open marine setting. Calcite is the most common mineral and chalky limestone is the dominant lithology, its characteristic of the Apollonia and Khoman formations. This type is stratigraphically controlled as no structural influence on the shallow zones. Total porosity could reach 35%. Type-III is mud-supported microfacies dominated mainly by matrix properties while type-I and type-II indicate further enhancement by dolomitization and secondary porosity. The bulk density is very low compared to type-I and type-II (about 2.66 gm/cc) close to sandstone rock density. The fine grain size of type-III minerals resulted in common micro-porosity which is well distributed all over the reservoir.

Well log-based rock mechanical parameters (ʋ, E, BI, and UCS) are evaluated. All properties are higher in older and deeper rocks towards type I. Elastic properties are found to be at low levels in type III compared to the other two types. The rock brittleness is found to increase with dolomitization. Type-I exhibits BI > 0.8 indicating a higher brittleness nature than type-II (0.65) while, type-III introduces ductile rock behavior (< 0.5).