Matruh Basin Research Articles

The Reservoir potential of Middle Jurassic sedimentary deposits in the Imhotep Field, Matruh Basin, North-Western Egypt

The Reservoir potential of Middle Jurassic sedimentary deposits in the Imhotep Field, Matruh Basin, North-Western Egypt

3D geological and petrophysical modeling of Alam El-Bueib Formation using well logs and seismic data in Matruh Field, northwestern Egypt

There are several productive petroleum fields in the North Western Desert (WD) of Egypt, which received extensive investigations regarding their petroleum potential. However, a few studies tackled the Matruh Oil Field, which contains the oil prolific Early Cretaceous Alam El-Bueib Formation (AEB Fm) reservoir. The reservoir intervals of the AEB Fm show substantial lithological variations across the basin. Therefore, it is necessary to analyze the vertical and lateral distributions in terms of their lithological and petrophysical properties. To achieve this objective, wireline logs of four wells and 20-2D seismic lines were used to construct a depth-structure contour map for the studied part of the field. This map was used to build the field’s structure model and to identify the fault patterns in the basin through several seismic lines. Analyses of well logs data and lithology were used to estimate the petrophysical properties of AEB sandstone units AEB-1, AEB-3A, AEB-3C, and AEB-6. Results show that the AEB-6 Unit is the most promising hydrocarbon-bearing unit. It has a net pay of 20–160 feet, a shale volume of 5–20%, an effective porosity of 14–20%, and a hydrocarbon saturation of 70–88%. The structure-depth maps indicate a number of normal faults with two principal NE-SW and NW–SE trends, which probably act as structural traps in the Matruh Oil Field. The constructed structure-depth maps and calculated petrophysical parameters were used to build a three-dimensional reservoir model. A blind well was used to validate the accuracy and reliability of the facies, porosity, and saturation models for the AEB Fm units, ensuring a good match between log-derived data and built models. The AEB Fm shows regional heterogeneous variations in its petrophysical characteristics. It exhibits unconventional reservoir characteristics in a N–S direction and conventional reservoir characteristics in an E–W direction. This observed heterogeneity shows the need to carry out further investigations to comprehensively assess the hydrocarbon potential of AEB Fm in different areas of the Matruh Basin.

Burial and thermal history simulation of the Middle Jurassic source rocks in Matruh basin, north Western Desert, Egypt

Burial and thermal history simulation of the Middle Jurassic source rocks in Matruh basin, north Western Desert, Egypt

Depositional environment and paleoclimate of the Middle Jurassic sedimentary rocks in Matruh Basin, Northwestern Desert, Egypt

Depositional environment and paleoclimate of the Middle Jurassic sedimentary rocks in Matruh Basin, Northwestern Desert, Egypt

Source rock evaluation of Jurassic rock units for Imhotep field, Matruh basin, Western Desert, Egypt

Source rock evaluation of Jurassic rock units for Imhotep field, Matruh basin, Western Desert, Egypt

Structural and tectonostratigraphic evolution of Matruh Basin, northern Western Desert, Egypt: An example of an inverted rift basin

The Matruh Basin is located in the northwestern part of the Western Desert of Egypt. Being part of the structurally complex northeast African margin, the basin underwent multiple phases of Mesozoic-Cenozoic deformation. Detailed structural analysis of the subsurface structures of this basin, using high-quality 3D seismic and well datasets, has identified two main fault sets: 1) Jurassic- Early Cretaceous (Barremian) NNE-striking normal faults; and 2) Late Cretaceous NW-striking normal faults. The older NNE-striking normal faults were later inverted due to Late Cretaceous compression forming fault-propagation folds (inversion anticlines) in their upper tips. This positive inversion initiated with the “Santonian Event” and continued into the Early Cenozoic. The NW-striking normal faults were not inverted due to their unfavorable orientations.Most inversion structures in the greater Western Desert trend E-W or ENE-WSW and reflect the reactivation of similarly oriented pre-existing normal faults. The NNE orientation of the old, major extensional structures in the Matruh Basin and the resulting control on the later inversion fabric reflects a very different fault architecture. This has dramatically impacted sedimentation patterns and potential hydrocarbon accumulations. The Matruh Basin illustrates the complexities that can be present along the North African Neotethyan margin and underlines the necessity to avoid regional generalizations where gaps in data may be present.

Sequence stratigraphic modeling and organic matter distribution of Jurassic deposits in the Imhotep Field, Matruh Basin, Western Desert, Egypt

Sequence stratigraphic modeling and organic matter distribution of Jurassic deposits in the Imhotep Field, Matruh Basin, Western Desert, Egypt

Source rock evaluation and burial history modeling of the Middle Jurassic Khatatba Formation in the West Kanayes Concession of Matruh Basin, North Western Desert, Egypt.

Source rock evaluation and burial history modeling of the Middle Jurassic Khatatba Formation in the West Kanayes Concession of Matruh Basin, North Western Desert, Egypt.

Integrated organic geochemical/petrographic and well logging analyses to evaluate the hydrocarbon source rock potential of the Middle Jurassic upper Khatatba Formation in Matruh Basin, northwestern Egypt

The present national and international pursuit of converting Egypt into a regional hub of natural gas in the East Mediterranean region resulted in conducting extensive exploration activities in several areas of northern Egypt. Therefore, organic petrographic, geochemical, and geophysical analyses were carried out on the upper Khatatba Formation from the OBA 2-2A well in the Matruh Basin.Restoration of the original sedimentological and geochemical characteristics of the upper Khatatba Formation suggest deposition of this formation in deltaic settings. Few shale and partly calcareous shale units of the Upper Safa and the uppermost Zahra members accumulated in TST in prodelta settings under dysoxic-anoxic conditions. These shale units had an original gas/oil-prone organic facies BC. Other shales and partly calcareous shales of the Upper Safa and Zahra members accumulated in HST in deltafront settings under relatively oxic conditions and had an original lower gas-prone organic facies C.The Upper Safa Member had an original active fair to excellent organic richness (0.76–7.35, avg. 3.38 TOCo(live) wt%) and hydrocarbon source rock potential (S2o: 2.22–17.97, avg. 8.05 mg HC/g org. C). It was characterised mainly by original active mixed gas/oil-prone kerogen type IIIo(live)-IIo(live) (HIo(live): 200.27–297.34, avg. 238.03 mg HC/g TOCo(live)) and subordinately by gas-prone kerogen type IIIo(live) (HIo(live): 181.50 mg HC/g TOCo(live)). The Upper Safa Member had original poor to fair proportions of active oil-prone (0.15–1.47, avg 0.68 TOCo(live, oil) wt%) and higher fair to very good proportions of active gas-prone (0.61–5.88, avg. 2.70 TOCo(live, gas) wt%) kerogens. The Upper Safa Member originally possessed poor to very good oil (S2o(oil): 0.44–3.59, avg. 1.16 mg HC/g org. C) and good to very good gas (S2o(gas): 1.77–14.37, avg. 6.44 mg HC/g org. C) generation potential. The carbonates and partly calcareous shales of the uppermost Safa and the Zahra members possessed poor oil and gas generation potential due to their organic-lean status.The present-day organic geochemical characterization indicates that the Upper Safa Member still shows active fair to excellent organic richness (0.68–6.75, avg. 3.11 TOCpd(live) wt%). However, this member shows a relatively lower present-day good to very good/excellent source rock potential (S2pd: 1.33–10.78, avg. 4.83 mg HC/g rock) and lower active kerogen quality IIIpd(live) (HIpd(live): 115.97–198.21, avg. 151.07 mg HC/g TOCpd(live)). This is related to the current high thermal maturation (gas-window: Tmax: 459–468, avg. 469 °C, thermal alteration index: TAI of 4-) and conversion of the original kerogen IIIo(live)-IIo(live) into oil and gas. The present-day high organic richness, high remaining generative potential, high shale volume of the thermally mature gas-prone kerogen, classify the Upper Safa Member as an active fair to excellent shale gas play in the Matruh Basin. Intrabasinal and interbasinal correlations across northwestern Egypt indicate that the upper Khatatba Formation shows locally and regionally dual source and reservoir rock characteristics due to the lateral facies changes.

Evaluation of hydrocarbon prospects by the use of 3D seismic data at the Cretaceous formations in Jade field, Matruh Basin, North Western Desert, Egypt

Evaluation of hydrocarbon prospects by the use of 3D seismic data at the Cretaceous formations in Jade field, Matruh Basin, North Western Desert, Egypt

Sequence stratigraphy and distribution of organic-rich Lower Cretaceous mixed clastic-carbonate strata in Matruh Basin, northwestern Egypt: Constrains on the Tethyan sea level changes, palaeoclimate, and tectonics

Integrated palynological, lithological, and geophysical analyses of the Lower Cretaceous (upper Hauterivian-Aptian) in Matruh Basin enabled conducting a high-resolution sequence stratigraphic analysis. Fluctuations of the continental/marine palynomorphs ratio reflect changes in the Tethyan 3rd order sea levels and are mirrored by eminent vertical changes in the spontaneous potential and the lithofacies. These are used with abundance of the marine phytoplanktons and opaque/translucent phytoclasts ratio to identify three 3rd order (SQ1: 132.4–120.8 Ma, SQ2: 120.8–115.2 Ma, and SQ3: 115.2–113 Ma) and seven 4th order genetic sequences and to study the impact of the allogenic and autogenic processes on their deposition.Deposition of the deltaic clastic systems tracts of the lower-middle Alam El Bueib (late Hauterivian-early Barremian) and Dahab (late Aptian) formations reflect the interaction between the regional humid climate and the Tethyan 3rd order sea levels, which superimposed the Tethyan 2nd order sea level. Interferences of minor regional tectonics were also important. The argillaceous deposits possess large amounts of terrestrial organic matter of low hydrogen index (HI: 185.8–211.5 mg HC/g TOC) indicating gas organic facies. These deposits show relatively high organic richness (1.81–2.50 TOC wt %) due to relatively low sediment dilution and water circulation (i.e. suboxic-anoxic conditions) and high primary productivity due to high riverine nutrient inputs.Deposition of the inner-middle shelf clastic-carbonate systems tracts of the upper Alam El Bueib and Alamein formations (latest Barremian-middle Aptian) reflects the interaction between the climatically induced low terrigenous influx and carbonate sedimentation due to shift to relatively dry climate, changes in the Tethyan 3rd order sea levels, and the middle Aptian regional minor uplift. These systems tracts show relatively large amounts of terrestrial organic matter, a notable marine organic matter signature, and intermediate HI (283.1–239.0 mg HC/g TOC) indicating gas/oil organic facies. The shales and siltstones are relatively organic richer (1.88–2.28 TOC wt %) than the pure and the argillaceous dolostones (1.46–1.94 TOC wt %). This organic richness is related to combined low sedimentation rates, low water circulation (i.e. dysoxic-suboxic to suboxic-anoxic conditions), and relatively high primary productivity.Overall, the Tethyan sea level changes, regional climate, and regional tectonics played a major role in the deposition of the organic-rich syn-rift Lower Cretaceous deposits in Matruh Basin.

Palynomorph biostratigraphy, palynofacies, thermal maturity and paleoenvironmental interpretation of the Bajocian–Aptian succession in the OBA D-8 Well, Matruh Basin, Egypt

A palynological study of 35 cutting samples from the Middle Jurassic–Lower Cretaceous section encountered in the OBA D-8 Well in the north Western Desert of Egypt yielded palynomorphs and particulate organic matter used to interpret the biostratigraphy, palynofacies, paleoenvironment, thermal maturation, and hydrocarbon potential of the Matruh Basin. The stratigraphically significant dinoflagellate cyst and sporomorph taxa recovered, which include Murospora florida, Aequitriradites spinulosus, Pilosisporites trichopapillosus, Callialasporites trilobatus, Tenua anaphrissa, Muderongia simplex, Systematophora sp., Gonyaulacysta jurassica, Korystocysta gochtii, Pareodinia ceratophora, and Dissiliodinium sp., permit an age assignment of the studied section as Bajocian to Aptian. Seven formal dinoflagellate cyst zones and four formal sporomorph zones are proposed for this time interval, in addition to differentiating four palynofacies assemblages and using the Rock-Eval Pyrolysis method to visually and geochemically evaluate the source rock potential. The 0.45–2.82 wt% TOC values of the studied samples indicate fair to good source rocks. An inner neritic depositional environment due to relatively high sea level is deduced for the Khatatba and Masajid formations using palynological proxies, as reflected in the lower percentages of sporomorphs relative to dinoflagellate cysts. During the Lower Cretaceous, a predominance of terrestrial sporomorphs in the Alam-El Bueib Formation suggests the advance of a fluvio-deltaic environment, possibly related to a significant sea level fall and regressive phase.

Palynostratigraphy and palaeoclimate of the Valanginian–Cenomanian subsurface succession in Hamza-1X well, Matruh Basin, Egypt

Diverse palynomorph assemblages of spores, pollen grains and dinoflagellate cysts have been yielded from the palynological analyses of 115 ditch cutting samples covering the Valanginian– Cenomanian succession encountered in Hamza-1X well, Matruh Basin, north Egypt. The complex sit- uations in the north Western Desert requires more revisited palynozones for better understanding of the subsurface successions therein. Consequently, the first downhole palyno-events will be very helpful in solving some issues concerning the age determination and correlation. Seventy palynomorph species (47 spores and pollen grains; 23 dinoflagellate cyst species) were identified from all the productive samples which used to divide the studied succession into numerous sporomorph and dinoflagellate biozones based on the last occurrence datum for the recovered marker taxa. Four sporomorph inter- val biozones and six dinoflagellate cyst interval biozones were differentiated from the same studied stratigraphic succession. The four sporomorph biozones are presented, in ascending order as follows: Aequitriradites spinulosus and Impardecispora apiverrucata Interval Zone (late Valanginian– early Barremian), Pilosisporites trichopapillosus I. Z. (late Barremian), Murospora florida I. Z. (early Aptian–late Aptian), and Elaterosporites klaszii I. Z. (early Albian– early Cenomanian). The seven dinoflagellate cysts biozones are Muderongia simplex I. Z. (late Valanginian–early Barremian), Pseudoceratium anaphrissum I. Z. (late Barremian– early Aptian), Cribroperidinium edwardsii I. Z. (early Aptian), Subtilisphaera perlucida I. Z. (late Aptian), Oligosphaerdium complex I. Z. (early– late Albian), Dinopterygium cladoides and Coronifera oceanica Assemblage Zone (early Cenomanian). From the palaeoclimatic point of view, the studied interval could be differentiated into two climatic intervals; the lower arid interval that comprises the Alam El Bueib Formation and dominated by the arid xerophyte elements like Sphaeripollenites and Classopollis. The upper humid interval represents the Alamein, Dahab, Kharita and Bahariya formations that is dominated by the humid hygrophyte elements, such as Murospora, Crybeolsporites, Elaterosporites, Afropollis and Deltoidospora.

Organic geochemical, palynofacies, and petrographic analyses examining the hydrocarbon potential of the Kharita Formation (Albian) in the Matruh Basin, northwestern Egypt

A recent study of selected samples from the Cretaceous (Albian) Kharita Formation of Egypt revealed very good to excellent source rock (SR) potential for six intraformational, organic-rich intervals. This work investigates the SR potential of the entire Kharita Formation across the Matruh Basin, using samples from two wells: the Abu Tunis 1X well from the central part of the basin, and the Siqeifa 1X well drilled on the eastern margin of the basin. More strongly reducing conditions were developed in the centre of the basin, and resulted in the deposition of more organic-rich shales by comparison to the less reducing conditions that prevailed on the eastern basin margin, where the shales contain less organic matter. Deltaic intraformational shales and carbonates in the Kharita Formation of Abu Tunis 1X constitute a significant 120 m net of the potential SR. The lower Kharita Formation contains 34 m net shale SR of good to very good/excellent organic richness, yielding values of 1.14–11.59 wt % total organic carbon (TOC). The organic matter has low Hydrogen Index (HI) values (184–389 mg HC/g TOC) and amorphous organic matter (AOM) and relatively high non-opaque phytoclast frequencies indicating mainly gas/oil-prone organofacies (kerogen Types III/II). The upper Kharita is rather important, containing 86 m net shale/carbonate SR that has fair to good organic richness (0.8–1.8 wt % TOC), and lower HI (126–250 mg HC/g TOC), a dominance of non-opaque phytoclasts, and subordinate AOM frequencies, which together indicate gas/oil-prone organofacies (kerogen III/II). In the Siqeifa 1X well, Kharita deltaic intraformational shales and shaley dolostones comprise 80 m net SR, which has mainly fair to good to less very good organic richness (0.8–2.1 wt % TOC), whilst low HI (93–220 mg HC/g TOC), dominance of non-opaque phytoclasts and subordinate AOM indicate gas-prone organofacies (kerogen Type III). A relative upward increase in deposition of lignite and coaly carbonaceous material supports a gas-prone organofacies. Whilst thermal maturity indices only point to immature to early mature (pre- to early oil-window) SRs in both the Abu Tunis 1X and Siqeifa 1X wells, hydrocarbon exploration focussing on this potential source rock may be justified in areas to the southeast of the Matruh Basin, where modelling indicates this unit may have reached the late mature oil- to main gas-generation windows.

Cretaceous (Hauterivian–Cenomanian) palaeoceanographic conditions in southeastern Tethys (Matruh Basin, Egypt): Implications for the Cretaceous climate of northeastern Gondwana

Quantitative palynological, sedimentological, and geophysical data analyses of the Cretaceous Abu Tunis 1X well from the Matruh Basin, northwestern Egypt indicate deposition of four major alternating regressive–transgressive successions. Sedimentation was largely affected by the Tethyan 2nd order sea level changes, with minor overprints by regional tectonics. The Lower Cretaceous part of the succession shows regressive sequences of deltafront to delta-top (upper Hauterivian–lowermost upper Barremian), delta channel (upper Aptian–middle Albian), and distal deltaic (upper Albian) settings that were interrupted by transgressive inner–proximal middle shelf deposits (uppermost Barremian–middle Aptian). These sediment packages correspond to Tethyan sea level fall from the late Hauterivian to late Barremian, and to the early–middle Aptian long-term sea level high stand. The Tethyan late Aptian–middle Albian long-term (2nd order) sea level rise was masked by regional late Aptian–Albian uplift, which affected deposition of the later regressive sequence. The Cenomanian shows a change in depositional setting from a proximal inner shelf (lower Cenomanian) to a middle shelf setting (middle–upper Cenomanian), corresponding to the Tethyan long-term latest early–late Cenomanian sea level rise.We demonstrate that northeastern Gondwana (Egypt) experienced different climatic conditions from other parts of the Northern Gondwana Phytogeographic Province. The climate in Egypt shifted from less warm and more humid conditions of the Hauterivian–early Barremian to a warmer and drier climate during the late Barremian–middle Aptian, although never becoming as dry as western Northern Gondwana. Warmer and more humid conditions were reestablished during the late Aptian and became even more accentuated during the Albian–Cenomanian, in contrast to the warm and much drier climate of Northern Gondwana at that time. Turonian climatic conditions may have been less humid as a result of the breakup of the Western Gondwanan supercontinent and the northeasterly drift of the African continent. The climatic conditions experienced in northeastern Gondwana developed through the early-mid Cretaceous as a result of changes in palaeolatitudinal position, variations in sea level, and shifts in the Intertropical Convergence Zone, which drove fluctuations between periods of warm humid and warm dry conditions.

Structural modeling of the Alam EL-Bueib Formation in the jade oil field, Western Desert, Egypt

The Jade oil field is located in the Matruh Basin in the northern portion of the Western Desert, Egypt. The region is one of the most productive areas for hydrocarbons in Egypt. The main producing reservoir in the area is the Cretaceous Alam-El Bueib Formation. The main goal of the present study was done through construction structural model using Petrel™ Schlumberger software by integrating thirty 2D seismic sections with eight digital well logs. Two-way time and depth structure maps were achieved, besides the geological cross section. Seismic and well log data are used to identify and correlate the four sandstone units of the Alam EL-Bueib Formation, AEB-3A, AEB-3D, AEB-3E and AEB-3G, where only the AEB-3D to 3G sandstones are hydrocarbon-bearing in the Jade oil field. The Alam EL-Bueib Formation in the Jade oil field structure dips slightly to the northwest as part of an anticlinal fold bounded by a northeast-southwest striking reversed fault, the main tectonic element of the study area. This fault was caused by compressional forces during the Syrian arc movement in Late Cretaceous. The area east of the main fault shows antithetic Riedel-shear faults (75° to the main fault) and a corresponding narrow graben to the south of the study area. The hydrocarbon-bearing Alam EL-Bueib Formation of the Jade oil field revealed the main trapping style following the tectonic evolution during Late Cretaceous. It so provides an excellent strategy in the well explored basins in the western Desert of Egypt.

Analysis of Well Log Data for the Evaluation of Gas Sand Reservoir of Alam El-Bueib (AEB) Formation, 3G Member, Jade-8 Well, Jade Field, Matruh Basin, Egypt

Analysis of Well Log Data for the Evaluation of Gas Sand Reservoir of Alam El-Bueib (AEB) Formation, 3G Member, Jade-8 Well, Jade Field, Matruh Basin, Egypt

3D Seismic Structural Analysis and Basin Modeling of the Matruh Basin, Western Desert, Egypt

In order to evaluate the hydrocarbon potential of the Matruh Basin, North Western Desert of Egypt, the tectonic history, basin analysis, and maturity modeling of the Albian-Cenomanian Formations of the Matruh Basin were investigated using well logs and 3D seismic data. Structural analysis of the tops of the Bahariya, Kharita, and Alamein Dolomite Formations reveals them to dip to the southeast. Burial history and subsidence curves show that the basin experienced a tectonic subsidence through the Middle-Late Jurassic and Early Cretaceous times. Thermal maturity models indicated that Cenomanian clastics of the Bahariya Formation are in the early mature stage in the east portions of the area, increasing to the mid maturity level in the southwestern parts. On the other hand, the Albian Kharita Formation exhibits a mid maturation level in the most parts of the area. The petroleum system of the Matruh Basin includes a generative (charge) subsystem with Middle Jurassic and Cenomanian sources (for oil/gas) and Turonian sources (for oil), with peak generation from Turonian to Eocene, and a migration-entrapment subsystem including expulsion and migration during Early Tertiary to Miocene into structures formed from Late Cretaceous to Eocene.

Multi-proxy approach to screen the hydrocarbon potential of the Jurassic succession in the Matruh Basin, North Western Desert, Egypt

This paper discusses the hydrocarbon potential of the Jurassic succession in a mature basin in Egypt as an important element of a larger petroleum system study. Prior to any organic petrographic and organic geochemical analyses, a palynological age dating of the originally undifferentiated Jurassic sequence was carried out to identify different formations under investigation. This was based on key bioevents of some recovered dinoflagellate cysts and the identified lithology. Palynological, TOC/Rock Eval pyrolysis (including modified Rock-Eval methods), and vitrinite reflectance (VRo%) data from a total of 14 samples taken from the uppermost lower-upper Jurassic sequence represented by the Wadi Natrun (Toarcian-Aalenian), Khatatba (late Bathonian-Callovian), and Masajid (Oxfordian) formations in the Abu Tunis-1× well, are presented. In addition, two samples from the Abu Tunis-1× well and the proximal (~32km to the east) Siqueifa-1× well, having the highest remaining hydrocarbon potential (S2 yields), were analyzed and their results were compared using modified pyrolysis programs. Although the data showed a good correlation between the TAI of the palynomorph assemblage, vitrinite reflectance, and Tmax from Rock-Eval pyrolysis in the shallower intervals, the correlation between VRo and Tmax was poor in the lower half of the studied succession (middle Khatatba and Wadi Natrun formations). The very low Tmax values indicate immature OM while VRo and TAI indicated middle stage of oil window to past peak oil generation. The reason for this discrepancy is that the deeper samples are reservoir rocks, not source rocks, and the majority of the organic matter is not composed of reactive kerogen but consists of migrated hydrocarbons and NSO compounds. Contamination due to oil-based mud (OBM) was eliminated because the Abu Tunis-1× well was drilled in 1969, prior to the extensive use of OBM in drilling. This study showed that a multi-proxy approach is the best way to screen the hydrocarbon potential in a thick succession that contains interbedded source and reservoir rocks.

Integrated palynological, organic geochemical, and sequence stratigraphic analyses of the middle to upper Cenomanian hydrocarbon reservoir/source Abu Roash “G” Member: A depositional model in northwestern Egypt

Abstract The current investigation provides further insight into the petroliferous characteristics of the Abu Roash “G” Member, which is regarded as an important rock unit for the Egyptian oil industry. Forty-seven samples covering the “G” Member were selected from the BED 14-1 and BED 2-4 wells in the Abu Gharadig Basin and from the Abu Tunis 1X well in the Matruh Basin, both of which are located in the north Western Desert. An independent dating of the “G” rocks of BED 2-4 by benthic foraminifera and ostracods, in addition to palynological dating, suggests a middle-late Cenomanian age and provides the biochronostratigraphic framework for the sequence stratigraphic analysis. Analysis of the vertical distribution of particulate organic matter defines three palynofacies types (PF). PF-1 represents the basal “G”, where shales of the BED wells and calcareous shale of Abu Tunis 1X were deposited during a relative sea level rise in an outer middle shelf environment that experienced a notable high primary productivity. Prevailing reducing (suboxic-anoxic) conditions supported preservation of very high amounts of amorphous organic matter (AOM) in PF-1. PF-2 is equated to shales of the middle “G” of BED 14-1 and BED 2-4 and to calcareous shales and limestone of the upper “G” in Abu Tunis 1X. PF-2 was deposited during a relative sea level fall in an inner middle shelf setting under better-developed suboxic-anoxic conditions. PF-3 corresponds to the upper “G” of BED 14-1 and BED 2-4 and represents the shallowest setting, where sandy and silty shales were deposited during a pronounced sea level fall in an inner shelf environment. The same suboxic-anoxic conditions were prevailing during deposition of PF-3. Three bioevents were recorded, which could be of palaeoecological and/or biostratigraphic significance. These are Senegalinium aenigmaticum-Dinopterygium cladoides peak, Dinopterygium cladoides-Dinopterygium alatum peak, and an acme of Classopollis brasiliensis. Sequence stratigraphy of a transect of the four studied sections was carried out to understand the response of the particulate organic matter distribution and depositional system to the sea level changes. Three third-order, depositional genetic sequences were recognized and correlated with the global sea level curve (KCe 2, KCe 3, and KCe 4). The early highstand systems tract (eHST) of the genetically related KCe 3 in all wells is characterized by relatively rich organic matter, where combined remarkably low water circulation and insignificant dilution of organic matter with coarse terrigenous material probably supported good preservation of organic matter. Spatial distribution of the “G” rocks shows lateral facies changes. This was inferred from sedimentation of an organic-poor (avg. 0.8 TOC wt %), coarse clastic (sandy shales) facies in the studied area in Abu Gharadig Basin. Sedimentation changes laterally into a northeast and northwest organic-rich, finer clastic (shale, calcareous shales, and argillaceous limestone) facies in the western Matruh Basin. The robust anoxic conditions and very low dilution of organic matter by terrigenous influx enhanced the organic richness (avg. 2.4 TOC wt %) of these rocks, which resulted in the formation of promising hydrocarbon source rocks. Thus, for a successful hydrocarbon exploration in the north Western Desert, the promising source section of the “G” Member would be associated with shales, calcareous shales, and argillaceous limestone lithologies. Its depositional environment is mainly confined to outer middle and inner middle shelf settings that have widespread suboxic-anoxic conditions and show eHST pattern. In contrast, the regressive intervals that are denoted by the lowstand systems tract (LST) and/or the late HST (lHST) typify the relatively coarse clastics as good quality reservoir rocks that are characterized by poor organic richness due to dilution with terrigenous influx.