1 Introduction

The Gulf of Suez sedimentary rift basin, with aerial coverage of around 19,000 km2, is the most prolific hydrocarbon provincial basin of Africa. It is delineated on both margins by large-scale NW-striking normal fault zones that define half-grabens (Jackson et al. 2006). The basin is developed as a result of the separation of the Arabian plate from the African plate. The basin hosts more than eighty hydrocarbon fields established based on 240 discoveries made from thousands of exploratory well drilling and these finds include up to 1 million bbl in the Precambrian-Quaternary reservoirs (Wescott et al. 2016), and thus of great interest to the Egyptian upstream industries (e.g., Alsharhan 2003). Recent discoveries in the Abu Rudeis Sidri development lease by ENI (2019) and Ramadan region by Dragon Oil (JPT 2022) had attracted the upstream community and rejuvenates the oil and gas exploration activities in the Gulf of Suez. The Gulf of Suez is structurally complex, and the new plays and untapped hydrocarbon pools can be accessed with new technological advancements (i.e., seismic imaging, drilling complex geometries etc.). Structural and property (facies and petrophysical) modeling are important can enhance the subsurface understanding of the potential reservoir intervals as well as producing reservoirs, that directly affects the forthcoming field development strategies, future well placements etc. (El-Gendy et al. 2017a, b, 2022; Nabawy and Barakat 2017; Barakat et al. 2022; Nabawy et al. 2022).

The present study focuses on the Upper Cretaceous sandstones of the October field from the Central Gulf of Suez Basin. The field started producing in 1977 and reached a time of peak production of 136,000 BOPD (barrels of oil per day) (Askar et al. 2020). Along with the Nubia sandstones, the upper Turonian Wata Formation and Coniacian-Santonian Matulla Formation of the Nezzazat Group formed key reservoirs in the October field (Lelek et al. 1992). Nezzazat reservoirs were developed later when Nubia was depleted (Hassan et al. 2006). The latest published production figure from the October field stands at 16,000 BOPD with high water cut (Noureldien and Nabil 2016).

Reservoir completion and production-related aspects are well published from the October field (Borling et al. 1996; Ibrahim et al. 1999; Hassan et al. 2006; Ibrahim et al. 2008; Nassar and Noureldien 2013; Askar et al. 2020). El-Ghamri et al. (2002) presented the oil generation and migration aspects. Sercombe et al. (1997, 2012) and Gawad et al. (2021b) interpreted the structural geology of the field and reservoir modeling aspects. Lashin and Mogren (2012) and Gawad et al. (2021a) characterized the source rock properties and analyzed the petroleum system of the October field. Kassem et al. (2020) studied the organic geochemical and isotope data of the Cenomanian–Turonian shales and limestones from the October field and linked the sediments with oceanic anoxic event 2 (OAE2) which produced organic-rich intervals. Kassem et al. (2021) inferred the geomechanical characteristics of the Cretaceous Nezzazat and Paleozoic Nubia reservoirs to infer the influences of fluid injection and depletion on reservoirs’ geomechanical stability and field development. Kassem et al. (2022) presented a microfacies analysis of the Wata Formation and inferred intertidal /shelf depositional settings.

Other works from the Nezzazat Group from the Central and Southern Gulf of Suez includes the analysis of reservoir geometry (Hasouba et al. 1992), glauconite effects on logs (El Bahr et al. 1992), lithology evaluation (Marttila and El Bahr 1994) and petrophysical rock typing of Matulla Formation (El Sharawy and Nabawy 2016). A detailed petrographic, diagenetic and petrophysical investigation of the Matulla and Wata clastic reservoirs from the October oil field are lacking in the literature, which have been the primary objective of our study. In this work, we have combined thin section petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), routine core analysis (RCAL), wireline logs and gas chromatography data to assess the reservoir properties of the Upper Cretaceous Matulla and Wata sandstone reservoirs from the October oil field, such integrated analysis were not attempted before. Principal objectives of the study include: (i) petrographic characteristics and rock constituents, (ii) diagenetic features, (iii) porosity and permeability distribution, (iv) permeability anisotropy, (v) wireline log-based quantitative petrophysical assessment and (vi) hydrocarbon characteristics based on gas chromatography data. Results have been discussed and inferences are drawn on the effect of diagenesis on reservoir properties.

2 Geological settings

The Gulf of Suez is a shallow, slightly arcuate, northwest-southeast-trending depression that is defined by longitude 32°10' and 34°E and latitude 27° and 30°N (Fig. 1). It forms an elongated graben with a length of around 320 km, a breadth of 30–80 km, and a sea depth of 40–60 m. The separation between Arabian and African plates during Cenozoic created this rift basin (Hempton 1987; Meshref 1990; Makris and Henke 1992; La Brecquet and Zitellini 1985). Rifting started in the late Oligocene to early Miocene, and continued until the late Miocene (Bosworth et al. 2020). The southern Suez rift ends by creating a triple junction with Gulf of Aqaba and Red Sea rifting. Meshref (1990) subdivided the Suez rift basin into various structural provinces based on dip variations within large fault blocks constituting of eroded horsts and deep grabens. The October Field is positioned in the central Gulf of Suez (Fig. 1) (EGPC 1996). An NNE striking cross fault divided the field into two main fault compartments with the northern compartment being at the down thrown side. The pre-rift stratigraphy displays a relatively uniform dip towards NE. The overlying Lower Miocene beds also dip to the NE.

Fig. 1
figure 1

Location of the studied field in the central Gulf of Suez Basin, as marked by red polygon. The structural trends are adapted from El-Gendy et al. (2017a)

Full size image

Figure 2 presents the lithostratigraphic succession of the October oil field, based on the interpreted and correlated formation tops from the four studied wells. Three major lithostratigraphic units classified the successions according to rifting events with different thicknesses and facies characteristics are: post-rift (post-Miocene), Miocene syn-rift, and pre-rift (ranging between Upper Eocene and Pre-Cambrian). The pre-rift mixed clastic and carbonate stratigraphy was deposited in terrestrial, shallow marine or marginal marine environments which were differentiated by non-depositional/erosional unconformities. The pre-rift sediments exhibit highly heterogeneous distribution laterally with minimum thickness being reported in the southern region and highest thickness in the central province. The Late Cretaceous stratigraphy is classified into the Cenomanian Raha Formation, overlain by Turonian Wata Formation and the Coniacian–Santonian Matulla Formation, mostly of shallow marine origin (Hassouba et al. 1992). The variation in thickness of the Wata and Matulla formations is clearly observed in the Gulf of Suez, indicating tectonic activity after the deposition of the Turonian (Farouk 2015). These three units form the Nezzazat Group which is overlain by the Brown Limestone and Sudr Formations (Schütz 1994). Hydrocarbons in the October field are produced from four reservoir intervals: the Carboniferous-Lower Cretaceous Nubian Sandstones, the Upper Cretaceous Nezzazat Group, the Lower Miocene Nukhul Formation, and the Asl Member of the Lower Miocene Upper Rudeis Formation (El-Ghamri et al. 2002). Based on numerous oil/source rock correlations, Abdine et al. (1992) concluded that the Brown Limestone Member of the mature Sudr Formation is the most probable source of oil in the October field. Middle Miocene regional uplift resulted in the Gulf of Suez becoming an enclosed basin with the deposition of extensive evaporites (Belayim, South Gharib and Zeit Formations) which provide a regional seal across the region (Abdine et al. 1992). The presence of trap-bounding faults and their sealing properties were reported to be critical for charging the October field and related structures (El-Ghamri et al. 2002).

Fig. 2
figure 2

Lithostratigraphic succession of the studied October oil field, Gulf of Suez Basin, Egypt based on the interpreted and correlated formation tops in the four studied wells. (Alsharhan 2003; El Diasty et al. 2020). This study focuses on the clastic reservoirs of the Matulla and Wata formations

Full size image

3 Data and methods

We have studied the Upper Cretaceous Matulla and Wata reservoirs from four wells drilled in the October field, A-10, B-6, A-3, and G-11 (Fig. 3). All these four wells were drilled till Nubia Formation, which was the primary producer of the October field. The well A-3 and B-6 were drilled in 1981 and 1983, respectively, and both the wells are now in shut in phase. G-11 and A-10 were drilled in 1993 as development wells. Presently G-11 is oil producing and A-10 is being used as a water injector well. The Matulla Formation was encountered between 10,941–11,342 ft, 11,005–11,207 ft, 10,204–10,915 ft, and 10,385–10,797 ft in the wells A-10, B-6, A-3, and G-11, respectively. The Wata Formation was encountered between 11,342–11,688, 11,207–11,570, and 10,797–11,160 ft in the wells A-10, B-6, and G-11, respectively. In the well A3, the Wata Formation was absent, and Matulla Formation directly overlies the Raha Formation due to tectonic uplift and faulting. Both the formations host mixed siliciclastic and carbonate intervals; however, this study focuses on the sandstone reservoir zones of the mentioned formations. The formation thicknesses in all the studied wells are presented in Fig. 2. A well log correlation panel is presented in Fig. 4. Conventional cores were retrieved from the Matulla and Wata Formations from three wells, A-10, G-11, and A-3. Thin section petrography, SEM and XRD were performed on 6 Matulla samples and 8 Wata samples from the wells A-10 and G-11. These datasets are used to infer mineralogical distribution, texture, diagenetic effects, porosity types and clay mineral phases present within the studied reservoirs. Gas chromatography data was studied from the well A-10. Based on the total gas and chromatographs (C1–C5), following gas ratios were estimated (Haworth et al. 1985):

$${\text{Wh}} = \left[ {\frac{{{\text{C}}2 + {\text{C}}3 + {\text{C}}4 + {\text{C}}5}}{{{\text{C}}1 + {\text{C}}2 + {\text{C}}3 + {\text{C}}4 + {\text{C}}5}}} \right]{*}100$$
(1)
$${\text{Bh}} = \frac{{{\text{C}}1 + {\text{C}}2}}{{{\text{C}}3 + {\text{C}}4 + {\text{C}}5}}$$
(2)
$${\text{Ch}} = \frac{{{\text{C}}4 + {\text{C}}5}}{{{\text{C}}3}}$$
(3)

where Wh, Bh and Ch denote wetness, balance and character ratios, respectively. Based on the value ranges of the estimated gas ratios, reservoir fluid types are inferred (Haworth et al. 1985; Mode et al. 2014; Pierson 2017).

Fig. 3
figure 3

Location of the studied wells in the October field

Full size image
Fig. 4
figure 4

Well log correlation panel using the four studied wells in the October oil field

Full size image

Routine core analysis provided direct measurements of porosity (Ф) and horizontal permeability (Kh) from 52 Matulla core plugs (46 measurements from the well A-3, 6 from G-11) and 6 Wata core plugs from A-10 and G-11. Vertical permeability (Kv) data was also available from the 46 Matulla plugs of the well A-3, which was utilized to infer the permeability anisotropy:

$${\lambda k} = { }\sqrt {\frac{{{\text{Kh}}}}{{{\text{Kv}}}}}$$
(4)

Wireline logs were recorded in all the wells, which were utilized for quantitative petrophysical interpretation. We determined the essential petrophysical parameters that include shale volume (Vsh, using gamma ray log), total and effective porosity (Φt and Φe, respectively, using neutron porosity, density and Vsh), water saturation (Sw, using Indonesian model), and bulk volume of water (BVW) (Buckles 1965; Poupon and Leveaux 1971; Asquith and Gibson 1982). Pickett plot was constructed to infer the input parameter values for Sw estimation (Pickett 1973). Net reservoir pay interval was distinguished based on the petrophysical cut offs of Vsh = 0.35 v/v, Фe = 0.1 v/v and Sw = 0.5 v/v, as commonly reported from Gulf of Suez (Ali et al. 2022).

4 Results

4.1 Petrographic investigation

4.1.1 Matulla reservoir

Thin section analysis indicates that the Matulla sandstones are well to moderately sorted, mature, fine to very fine-grained, subrounded to subangular. Framework grains are predominantly quartz, feldspar, minor rock fragments along with well-rounded glauconite grains/peloids (Fig. 5). Moderate to slight compaction and grain to grain pressure solution results in a slightly inhomogeneous packing of framework grains. Leaching of feldspar, quartz cementation and overgrowths along with minor pyrites are commonly observed in all the Matulla thin sections (Fig. 5). Matrix consists predominantly of clayey pseudomatrix which results from the compaction/alteration of argillaceous rock fragments (Fig. 5). Pore-filling kaolinite clay forms as an alteration product of the pseudomatrix which resembles detrital matrix (Fig. 5). Calcite cementation is not common, it was observed in one of the thin sections (Fig. 5d). Primary intergranular porosity is dominant which exhibits good interconnectivity, indicated by blue dye impregnation in all the thin sections (Fig. 5). Dissolution of unstable framework grains produced secondary pores (Fig. 5a, c, d). Permeability is reduced due clayey pseudomatrix, pressure solution among quartz grains, and the discontinuous nature of the organic-rich, clayey lamina. SEM images indicated quartz framework grains with overgrowth and dominant intergranular porosities (Fig. 6). Pore-filling authigenic clay (Fig. 6a, b, d) and kaolinite booklets (Fig. 6c, d) are commonly observed along with minor calcite cements (Fig. 6d).

Fig. 5
figure 5

Optical photomicrographs of Matulla sandstones under plane polar at a 10,716 ft, sample 11A, b 10,723 ft, sample 18A, c 10,732 ft, sample 27A, and d 10,773 ft, sample 53A from the well G-11, indicating subangular to subrounded quartz (Q), feldspar (F), minor rounded glauconite (G), illitic lithic fragments (L), pore-filling kaolinite (K), clayey pseudomatrix (C), pyrite (P), feldspar dissolution (red arrows), quartz overgrowth cementation (yellow arrows), pore-filling calcite cement (blue arrows). Intergranular porosity is represented by blue dye. Field of view is 1 mm

Full size image
Fig. 6
figure 6

SEM images of Matulla sandstones at a 10,723 ft, sample 18A, b 10,732 ft, sample 27A, c 10,777.5 ft, sample 57A, and d 10,773 ft, sample 53A from the well G-11, indicating quartz framework grains (Q) with intergranular porosities (green arrows), fine crystalline pore-filling authigenic clays (C), quartz overgrowth cementation (yellow arrows), pore-filling kaolinite (K), calcite cementation (blue arrow). Scale bar is 10 microns

Full size image

4.1.2 Wata reservoir

Thin section analysis indicates that the Wata sandstones are moderate-well sorted, mature, very fine- to fine-grained, subrounded to subangular, containing abundant clayey material (Fig. 7). Moderate compaction, pressure solution, quartz overgrowth cement, and calcite cement has given the rock a spotty "welded" appearance and resulted in a slight inhomogeneity of packing. Framework grains are predominantly quartz, feldspar, and lesser amounts of rock fragments. Minor siderite is observed in few thin sections (Fig. 7a). Matrix consists predominantly of clayey pseudomatrix (Fig. 7b–d) which results from the compaction/alteration of argillaceous rock fragments. Some detrital clay is suspected as matrix due to the finely laminated texture of the rock, but it is often difficult to distinguish from pseudomatrix. Extensive feldspar leaching (Fig. 7a, c), quartz overgrowth cements (Fig. 7a–c), pressure solution among quartz grains, authigenic kaolinite (Fig. 7a, c) and chloritization of argillaceous rock fragments (Fig. 7d) are commonly observed in the Wata thin sections. Pore system consists of primary intergranular porosity with good pore connectivity and feldspar dissolution-induced secondary porosity. SEM images indicated quartz framework grains with overgrowth and intergranular porosities (Fig. 8b–d). Dissolution of feldspar grains along the cleavage planes are observed in SEM (Fig. 8a) contributing to secondary porosity. SEM also reveals abundant pore-filling kaolinite booklets (Fig. 8c, d), authigenic clays (Fig. 8b, d) and alteration rims composed of chlorites (Fig. 8b).

Fig. 7
figure 7

Optical photomicrographs of Wata sandstones under plane polar at a 11,580.2 ft, sample 22A, Field of view is 0.5 mm, b 11,569.5 ft, sample 17A, Field of view is 1 mm, c 11,581.3 ft, sample 23A, and d 11,584.7 ft, sample 26A from the well A-10, indicating subangular to subrounded quartz (Q), feldspar (F), lithic fragments (L), minor rounded glauconite (G), pore-filling kaolinite (K), clayey pseudomatrix (C), pyrite (P), feldspar dissolution (red arrows), quartz overgrowth cementation (yellow arrows), pore-filling calcite cement (blue arrows), chlorite rims surrounding quartz grains (black arrows), minor siderite (Sid). Intergranular porosity is represented by blue dye

Full size image
Fig. 8
figure 8

SEM images of Matulla sandstones at a 11,580.2 ft, sample 22A, b 11,569.5 ft, sample 17A, c 11,581.3 ft, sample 23A, and d 11,584.7 ft, sample 26A from the well A-10, indicating quartz framework grains (Q) with intergranular porosities (green arrows), feldspar (F) dissolution along the cleavage planes, alteration rim formed of chlorite (black arrows) defining relict grain, fine crystalline pore-filling authigenic clays (C), quartz overgrowth cementation (yellow arrows), pore-filling kaolinite booklets (K). Scale bar is 10 microns

Full size image

4.1.3 XRD results

The XRD measurements from the Matulla samples of the well G-11 indicates quartz to be the most dominant mineral with abundance ranging between 69 and 95%, along with 1–7% total feldspar (average ~ 4%), minor siderite (0.5–1%) and pyrite (0–0.5%) (Fig. 9a). Based on the petrographic analysis, the studied Matulla and Wata reservoirs are classified as glauconitic subarkose quartz arenites, following the sandstone classification scheme provided by Dott (1964). Carbonates are present in trace amounts, however one sample (no. 53A) exhibits ~ 5% calcite, which was also observed in the thin section (Fig. 5d) and SEM images (Fig. 6d) as pore filling cements. The total clay volume of the Matulla samples varies between 4 and 23%, which is composed of mostly kaolinite, chlorite, and mixed clay (illite/smectite) (Fig. 9b).

Fig. 9
figure 9

XRD results of Matulla sandstone from the well G-11, indicating a mineral constituents and b clay fraction

Full size image

The Wata sandstone samples from the wells A-10 and G-11 also exhibits similar characteristics, with quartz being the most dominant mineral (60–83%) along with 6–13% feldspar (average ~ 8%) (Fig. 10a). Siderite and pyrite are present in trace quantities. Average clay volume in the eight samples is 18% (Fig. 10a), dominated by kaolinite and chlorite (Fig. 10b), as also seen in SEM images (Fig. 8b–d).

Fig. 10
figure 10

XRD results of Wata sandstone from the wells A-10 and G-11, indicating a mineral constituents and b clay fraction

Full size image

4.2 Petrophysical assessment

4.2.1 Routine core analysis

Porosity and permeability of the two studied reservoirs are inferred from direct core measurements from three wells, A-10, G-11, and A-3. The Matulla sandstones exhibit a wide porosity (4.5–27.1%) and horizontal permeability (0.03–170 mD) distribution indicating micro- to megaporosity (Fig. 11). The average porosity and permeability of Matulla sandstone are higher in the well G-11 (2 µm < R35 < 10 µm, megaporous) than well A-3. The Wata samples, in comparison, exhibit 21.3–25.6% porosity and 63.7–412 mD permeability indicating macro- to megaporosity (Fig. 11).

Fig. 11
figure 11

Relationship between core-derived porosity and horizontal permeability (Kh) of the Matulla and Wata sandstone reservoirs from the October field. R35 denotes the pore throat radius (Kolodzie 1980)

Full size image

Vertical permeability measurements were available only for Matulla reservoir from the well A-3, which ranges between 0.02 and 185 mD (Fig. 12a). Most of the measurements indicate Kv/Kh < 1 representing predominantly primary depositional fabric over secondary fabrics (Fig. 12a). A cross plot between horizontal permeability and permeability anisotropy is presented in Fig. 12b (Leila et al. 2023). Permeability anisotropy of the Matulla sandstones range between 0.17 and 19.5, however majority of the data distribution indicates 1 < λk < 2, indicating dominantly isotropic pore system (Fig. 12b). Certain degree of horizontal pore communication (scattered or connected) is also observed with minor vertical pore connectivity. Such inferences could not be made on Wata reservoir due to the unavailability of Kv measurements in any of the wells. Statistical summary of the core-measured porosity and permeability of the two studied sandstone reservoirs is presented in Table 1. A higher CV (coefficient of variation) value is indicative of wider data distribution, as has been the case in the Matulla porosity and permeability measurements, especially from the well A3.

Fig. 12
figure 12

Relationship between a horizontal permeability (Kh) and vertical permeability (Kv), b permeability anisotropy (λk) and Kh, from Matulla sandstone reservoir from the well A-3

Full size image
Table 1 Statistical summary of the core-measured porosity, horizontal and vertical permeability of the Matulla (52 samples) and Wata (6 samples) sandstone reservoirs from the three cored wells. ‘Avg’ and ‘CV’ denote the average values and coefficient of variation
Full size table

4.2.2 Wireline log analysis

Wireline log-based petrophysical assessment was utilized to quantify the reservoir properties of the Matulla and Wata sandstones. The analysis involves the estimation of key petrophysical properties and net pay thickness. The results from three of the studied wells are presented in Figs. 15, 16, 17 and 18. To characterize the lithologies, we generated the cross-plots between bulk-density and neutron porosity (Fig. 13) and matrix density vs. matrix slowness (Fig. 14). Both the studied formations exhibit the influence of carbonates. It is to be noted that pore-filling carbonate cements were observed in the thin sections as well as SEM images, which corroborates well with the observations from the mentioned cross-plots. For estimating Sw, we have utilized a = 1, m = 2, n = 2 and Rw = 0.03 ohmm. It is to be noted that using default input parameter values in Sw calculation and constant Rw regardless of change in the formation temperature may introduce uncertainties in the Sw estimation.

Fig. 13
figure 13

Cross-plot between bulk-density and neutron porosity of the Matulla and Wata Formations (including the reservoir pay zones) indicating the lithological composition, from the well A-10

Full size image
Fig. 14
figure 14

Cross-plot between matrix density (RHOMAA) and matrix slowness (DTMAA) (Schlumberger 1972) of the Matulla and Wata Formations from the well B-6 indicating the effect of calcareous matrix within the studied reservoirs

Full size image

The core-measured porosity available from routine core analysis of three wells (A-3, A-10, and G-11) were plotted along with the petrophysical composite plots (Figs. 15, 16, 17) which correlates well with the log-based porosity (Фt) estimations. Matulla Formation exhibits a lower average shale volume, higher effective porosity, and Sw in the well A-10 than G-11, thus contributing to higher net pay thickness based on the utilized petrophysical cut-offs. Key observation from the Matulla Formation of the well A-10 is that Matulla hosts two potential pay zones in the upper (0.1 < Фt < 0.22, Sw ~ 0.4 v/v, 0.1 > BVW > 0.06) and lower (0.1 < Фt < 0.25, 0.3 > Sw > 0.1, BVW < 0.06) intervals (Figs. 15, 16, 17), which were also observed in the well G-11. The middle Matulla in G-11 also consists of pay intervals with 0.1 < Vsh < 0.3, 0.2 < Фt < 0.3, 0.5 > Sw > 0.2, 0.12 > BVW > 0.06 (Figs. 15, 16, 17); the same correlated interval in the well A-10 exhibits Sw > 0.5 v/v, therefore not inferred as pay zone (Figs. 15, 16, 17).

Fig. 15
figure 15

Petrophysical interpretation of the Matulla Formation from the well A-3 indicating key petrophysical properties assessed from wireline logs (GR = gamma ray, RHOB = bulk-density, NPHI = neutron porosity). Red dots on the Total porosity (Фt) track represent the measurements from routine core analysis in the Matulla interval in A-3

Full size image
Fig. 16
figure 16

Petrophysical interpretation of the Matulla Formation from the well A-10 indicating key petrophysical properties assessed from wireline logs (GR = gamma ray, RHOB = bulk-density, NPHI = neutron porosity)

Full size image
Fig. 17
figure 17

Petrophysical interpretation of the Matulla Formation from the well G-11 indicating key petrophysical properties assessed from wireline logs (GR = gamma ray, RHOB = bulk-density, NPHI = neutron porosity). Red dots on the Total porosity (Фt) track represent the six measurements from routine core analysis in the Matulla interval in G-11

Full size image

The Wata Formation from the well A-10 (Fig. 18) exhibits a very consistent clean GR (< 30 api), high resistivity (~ 200 ohmm) zone with density-neutron porosity cross over in the lower interval. This interval exhibits 30 > Vsh > 5, Фt up to 0.25 v/v, and 0.25 > Sw > 0.20, and a 65 ft of net pay is inferred.

Fig. 18
figure 18

Petrophysical interpretation of the Wata Formation from the well A-10 indicating key petrophysical properties assessed from wireline logs (GR = gamma ray, RHOB = bulk-density, NPHI = neutron porosity). Red dots on the Total porosity (Фt) track represent the four measurements from routine core analysis in the Wata interval in A-10

Full size image

4.3 Gas chromatography

Mudlogging data was analysed from the well A-10, where Matulla and Wata pay zones are inferred based on petrophysical cut offs. Calculated wetness (Wh) varies between 17.5 and 40, which indicates the presence of oil (Fig. 19) along with Ch < 0.5. In the Matulla pay zones, Bh ≥ Wh due higher C1 and C2 peaks, while Wata reservoir exhibits good separation between Wh and Bh. Usually, Bh <  < Wh indicates the possibility of residual oil, which is not the case for the studied reservoirs here (Fig. 19). We utilized C1/C2 ratio as a quick look indicator. The Matulla pay zones indicate C1/C2 varying between 3 and 7, which suggests the presence of low gravity (10–15 API) to medium gravity oil (15–35 API). The Wata pay zone indicates C1/C2 ~ 10.74 in the top part, which is indicative of gas, then it decreases to < 10, i.e., oil zone (Fig. 19). This may indicate a gas-oil contact within Wata. This observation is also supported by that fact that Ch > 0.5 in the top part of the Wata pays which indicates high GOR oil. However, such fluid contacts need to be confirmed by formation pressure measurements and change in fluid gradients, which were unfortunately not recorded in the studied wells. Since both the reservoir zones exhibit C1/C4 ratio higher than C1/C3 ratio, we infer that the studied reservoirs are not water wet (Fig. 19).

Fig. 19
figure 19

Gas analysis of the Matulla and Wata Formations, well A-10 using the chromatograph data [Wh = wetness, Bh = balance, Ch = character ratio]. Grey shaded intervals indicate the net pay zones based on petrophysical cut offs

Full size image

5 Discussions

5.1 Comments on depositional environment

The pre-rift sediments of the Gulf of Suez Basin were deposited in continental margin sags. The first subsidence cycle deposited clastic Nubia Formation during Carboniferous-Lower Cretaceous period, while the second subsidence cycle commenced from Upper Cretaceous and deposited mixed siliciclastic-carbonate sediments (Atia et al. 2015). Hassouba et al. (1992) reported shallow marine origin of the Matulla and Wata formations. Based on the palynofacies assemblages, El Diasty et al. (2014) inferred that Matulla sediments were deposited in a shelf setting, possibly near the shorelines. El-Azabi and El-Araby (2007) interpreted the primary sedimentary structures and architectural elements of the Matulla interval and interpreted that the Matulla clastic facies were deposited in a foreshore-shoreface to shallow subtidal environment under the influence of variable wave energy conditions. Kassem (2018) inferred lower intertidal to slightly deep subtidal settings for Matulla sandstones and deciphered that the main oil reservoir of lower Matulla consists of a tidal channel. In a recent work, Kassem et al. (2022) presented a microfacies analysis of the Wata Formation and inferred an intertidal/shelf depositional setting. The fine to very fine-grained sandstones of the studied Matulla and Wata reservoirs include glauconites, as seen in the thin sections (Figs. 5a, 5d, 7b). Glauconites are widely reported from Cretaceous marine sediments deposited in a warm climate (Banerjee et al. 2016). There are many reported examples of glauconitic sandstones from Egypt which were deposited in a shoreface-shallow shelf environment during Tethys transgression which had occurred during Cretaceous (Said 1990; Catuneanu et al. 2006; Khalifa and Catuneanu 2008; Baioumy and Boulis 2012). Glauconites are also reported from the Matulla sandstones from the nearby July oil field (Ali et al. 2022). Based on the petrographic observations, a shallow marine depositional environment is assigned to the studied reservoirs, which corroborates with the findings of previous researchers from other parts of the Gulf of Suez Basin.

5.2 Diagenetic factors

Thin section and SEM analyses indicate that the studied Matulla and Wata reservoirs have been largely affected by diagenetic alterations. The early diagenetic changes include clay infiltration (Figs. 5a, 7b–d), quartz overgrowth cements and pressure solution among quartz grains (Figs. 5a–c, 7a–c). Later stage of diagenesis resulted in extensive leaching and dissolution of feldspar grains (Figs. 5c, 7c, 8a), chloritized alteration rims surrounding quartz grains (Figs. 7d, 8b), calcite cementation (Figs. 5d, 6d, 7b) and kaolinite precipitation (Figs. 5, 6c, d, 7a, d, 8b–d). Pyrites formed at much later stage (Fig. 5a, d). Concavo-convex grain boundaries and point to point boundaries along with grain to grain pressure solutions resulted in a slightly inhomogeneous packing of framework grains, which indicate variable degrees of compaction affecting the two studied reservoirs.

Cementation can have a tremendous negative effect on reservoir quality. Worden and Morad (2000) reported loss of almost half of the original rock porosity due to cementation. Both the reservoirs indicated certain degree of calcite cementation (Figs. 5d, 6d, 7b); however not observed in every sample. XRD indicates 0.5–5% calcite in Matulla and Wata reservoirs. Thin sections and SEM indicate kaolinite is the most prominent clay mineral phase present in both the reservoirs. Kaolinite is observed in all the samples in the form of booklets filling the pore spaces (Figs. 5, 6c, d, 7a, d, 8b–d). Cao et al. (2017) inferred that kaolinites commonly occur because of feldspar dissolution in warm and humid climatic conditions. Chlorites were not seen in Matulla samples; however, it occurs as coatings surrounding quartz grains (Fig. 7d) which generally forms in the early diagenesis (Dowey et al. 2012; Freiburg et al. 2016) and favoured by the presence of iron-rich clays (Zhu et al. 2017). Such chlorite rims reduce surface area for further quartz cementation and stops overgrowth, thus helps in porosity preservation (Nguyen et al. 2013; Hansen et al. 2017). Clay pseudomatrix is commonly observed in all the samples from Matulla and Wata, which results from the compaction/alteration of argillaceous rock fragments. Some detrital clay is suspected as matrix due to the finely laminated texture of the rock, but it is often difficult to distinguish from pseudomatrix.

Primary intergranular porosity is dominant, while feldspar dissolution contributed to secondary porosity. Dissolution has been observed along the feldspar cleavage planes (Fig. 8a) and inferred as reservoir quality enhancing diagenetic agent. With increase in overburden burial and temperature, feldspar becomes chemically unstable (Ma et al. 2017) and can experience dissolution due to its interaction with low pH meteoric water (Zhang et al. 2018).

5.3 Inferences on reservoir petrophysical properties

Reservoir storage capacity and flow potential directly affects the production scenario, economics, and field development strategies. The studied Matulla and Wata reservoirs predominantly consist of primary intergranular porosity, as seen in all the thin sections. All samples have good, interconnected pores, but varying pore-throat sizes based on packing and grain-size distribution. Diagenesis has critical effects on the reservoir quality, i.e., it can significantly enhance or diminish reservoir qualities. This study identifies dissolution as a porosity enhancing factor. Secondary pores, such as grain moulds and "honey-comb" micropores, are the result of dissolution of unstable feldspar grains. At the same time clay infiltration, silica and calcite cementation occurred as contributed to porosity reduction. Majority of the feldspar grains of both the reservoirs are observed to be affected by dissolution. Cross plots between total feldspar content (from XRD) and core-measured porosity (Fig. 20a) and permeability (Fig. 21a) indicate that these increase with the increase in feldspar content within Matulla and Wata reservoirs. Figures 20b and 21b represent the negative effect of pore-filling clay on reservoir porosity and permeability.

Fig. 20
figure 20

Effect of a feldspar (dissolution) and b clay content on reservoir porosity

Full size image
Fig. 21
figure 21

Effect of a feldspar (dissolution) and b clay content on reservoir permeability

Full size image

In general, the Wata Formation shows higher hydrocarbon saturation when compared with the Matulla interval. However, Matulla Formation hosts multiple pay intervals when compared to Wata. The Matulla contributed to net pay in the well G-11 but exhibited higher water saturation in the well A-10. Also, to be noted that, the studied formations exhibit large thickness variations in these wells indicating high heterogeneity vertically as well as laterally. The absence of the Wata Formation in the well A3 is contributed by the faults or tectonic uplift, where we encountered Raha Formation right below the Matulla interval. This indicates lateral variability within Matulla and Wata. Similar observations were also reported by El-Ghamri et al. (2002) who inferred that the Matulla and Wata sandstones have high lateral and vertical heterogeneity in terms of continuity, thickness, and oil–water boundary.

6 Conclusions

Based on the integrated analysis using the petrographic thin sections, SEM, XRD, routine core analysis, gas chromatography, and wireline logs, we have assessed the reservoir characteristics of the Matulla and Wata clastic reservoirs from the October field. Our conclusions are summarised as below:

  • The analysed sandstones of the Matulla and Wata reservoirs are inferred as glauconite-bearing subarkose quartz arenites. The general composition of each sample is very similar with only subtle differences in relative percentages of feldspars, argillaceous rock fragments, clayey pseudomatrix, and/or calcite cement.

  • These changes correspond with the overall rock texture/fabric, in that with increasing planar lamina, there is a general increase in the pseudomatrix content of the rock. The feldspathic and lithic content of the sands is thought to be slightly lower than the original content due to the dissolution and partial dissolution of many of these unstable constituents.

  • Gas chromatography and wireline log-based quantitative petrophysical assessment indicates that the Matulla and Wata sandstones are oil bearing reservoirs with high vertical and lateral heterogeneities in net pay distribution.

  • The meso-megaporous reservoirs are dominated by primary intergranular porosity along with the secondary porosity contribution by feldspar dissolution. Clay infiltration and carbonate cementation reduced the reservoir qualities to a certain degree but overall, both the reservoirs exhibit excellent properties.