Fatma S. Ramadan

Alam El Bueib reservoir characterization, Tut oil field, North Western Desert, Egypt

An integrated petrophysical well log and core data analysis of the Alam El Bueib-3D (AEB-3D) and Alam El Bueib-3E (AEB-3E) reservoirs, Tut oil field, North Western Desert, Egypt, allows the evaluation of those parameters critical to their reservoir characterization. The determined reservoir properties investigated are lithology, depositional paleoenvironments, shale volume, porosity, fluid saturation and net pay thickness. As the analysis of reservoir pressure is essential to specify the driving mechanisms that control the behavior of fluids within reservoirs, pressure analysis identified the Alam El Bueib-3D reservoir to be partial water drive and Alam El Bueib-3E to be an active water drive. In addition, the pressure analysis identified two additional hydrocarbon-bearing reservoirs in the Alam El Bueib-3D. Stacking patterns of the Alam El Bueib-3D reservoirs are generally fining upward sequences reflecting fluvial to braided fluvial paleoenvironments. The Alam El Bueib-3E channel shows blocky patterns with sharp bases and tops diagnostic of distributary channels. Statistical analysis of core permeability and porosity values of the Alam El Bueib reservoirs indicate very good reservoir quality. Scatter diagrams of porosity values derived from core analysis for the AEB-3D and AEB-3E reservoirs reveal correlation coefficient (r) values of 0.93 and 0.64, respectively, indicating strong linear relationships. Plots of porosity values against permeability values also show strong linear relationships in all the reservoirs indicating that the AEB-3D and the AEB-3E are permeable and with strong pore communication. The permeability measurements indicate restricted reservoir heterogeneity as plots of vertical permeability values against horizontal permeability values exhibit linear trends. Altogether, the reservoir characterization of the Alam El Bueib reservoirs demonstrates their excellent potential for hydrocarbon production.

Isopach, lithofacies changes, and source rocks chracteristics of Khatatba and Alam El Bueib formations of some wells in North East Western Desert, Egypt

ABSTRACT The present work deals with isopach, lithofacies changes, and source rock chracteristics of Khatatba and Alam El Bueib formations of some wells in North East Western Desert. Isopach and lithofacies changes showed that the thickness of Khatatba Formation increases toward the south western direction and decreases toward northern parts, and the sediments consisting of sandstone and shale facies indicate a shallow marine environment. Alam El-Bueib sediments increase toward the north direction, and argillaceous sandstone facies reflect terrestrial-to-shallow marine environment. The geochemical analysis showed that Khatatba Formation bears a mature source rock and has poor-to-good generating capability for both oil and gas and lie within the early generation window and oil window. Alam El Buieb Formation constitutes a mature source rock and has poor-to-good generating capability for both oil and gas. It can be stated that Khatatba and Alam El Buieb are the main source rock for hydrocarbon accumulations rich with organic sediments and could be considered as effective source rocks for generating hydrocarbons in the the studied wells.

Geochemical Characteristics of Crude Oils From Ras Gharib Oilfields in the Central Gulf of Suez, Egypt

Four representative oil samples have been collected from productive wells, namely: Gharib-164, Gharib-163, Gharib-106, and Gharib-116, scattered within the Ras Gharib oilfield located in the central Gulf of Suez. Their chemical composition, API gravity, sulfur content, and asphaltene content were determined. Saturated hydrocarbon fractions were subjected to gas chromatography. Terpanes and steranes biomarkers have been determined using gas chromatography-mass spectroscopy in order to characterize the type of organo-facies, oil classes, depositional environments, and to assess the thermal maturity level for oil generation. The results showed that the studied oils are belonging to normal oil classes with no heavy biodegradation. It has been found that mature oils are generated from marine shales and carbonates are enriched in marine algae with contributions from terrestrial organic matters. Biomarker analyses suggest that the crude oils are more mature and sources are derived mainly from mixed organic sources from terrestrial and marine inputs contribution to the biomass from algae and plankton in different saline environments.

Sedimentological and geochemical evidence to elucidate an evaporitic–carbonate paleoenvironment, Middle Miocene Red Sea coast, Egypt

Lithologic succession, microscopic examination as well as X-ray diffraction and chemical data revealed that the surface Middle Miocene evaporites of Wadi Quei are composed of anhydrite beds intercalated with carbonate and green shale, whilst the subsurface evaporites of Gemsa locality are composed of gypsum, anhydrite, carbonates and celestite with a rare amount of halite. The anhydrite is found to be formed diagenetically after gypsum. The carbonate is interpreted as having been of biogenic origin. The strong smell of H2S and golden crystals of pyrite at Wadi Quei beds are indications of the biogenic action of sulphate-reducing bacteria in the presence of organic matter. It is suggested that the evaporite sequence which was deposited in a supratidal sabkha environment is characterized by alkaline-reducing conditions. The presence of nodular gypsum at Gemsa locality is probably deposited in a supratidal environment with oscillation of sea level.

Oil: Source rock correlations of Al Baraka oil field, Komombo basin, South Egypt: An implication from biomarkers characteristics

ABSTRACT The objectives of this study are the correlation between the oil samples recovered from the Lower Cretaceous reservoirs and Lower and Upper Cretaceous source rocks. The investigated biomarkers of five oils indicated the oils were derived from mixed marine and terrigenous (lacustrine) organic matter and deposited under suboxic to anoxic conditions. These oils were also generated from source rocks of high thermal maturity at the peak oil window. So, based on the molecular indicators of organic source input,depositional environment and maturity parameters of oils and extracts, we can conclude that the oil recovered from Al Baraka oil field were derived from Lower Cretaceous source rocks especially KomOmbo (B) source rocks where it reached the oil window. Furthermore, we can indicate that the other lower Cretaceous formations as Abu Ballas Formation will have the opportunity to generate and expel oil at the deeper part of the basin as shown in the eastern part of the basin.

Organic richness, hydrocarbon potentiality, maturity, and timing of petroleum generation of the Cretaceous and Miocene source rocks in the central Gulf of Suez, Egypt

ABSTRACT Total organic carbon (TOC) and pyrolysis analysis of the Cretaceous and Miocene source rocks in the central Gulf of Suez were evaluated throughout the 25 rock samples collected from 6 formations, namely Wata, Raha, Nubia “A” (Cretaceous source rocks); and Nukhul, Zeit, and Belayim (Miocene source rocks) from Gharib-252, Gharib-153, Gharib-163, Gharib-164, Gharib-167, and Gharib-165 wells. These data are used to study the probabilities of the source rock in the Cretaceous and Miocene source rocks in the central Gulf of Suez for the hydrocarbon generation through identifying the organic richness, type of organic matters, and thermal maturation of these organic materials. The results revealed that the Cretaceous formations are immature source rocks, ranging from fair to good source rocks and have kerogen of type III and type III/II. Meanwhile, Miocene source rocks, ranging from immature to marginally mature source rocks, are considered to range from good to very good source rocks for potential generation of both oil and gas and are characterized by kerogen of type III/II and type II.

The Nature of Pre-Miocene and Miocene Sediments in the Offshore Northern Part of the Gulf of Suez, Egypt

The present study deals with subsurface geology pre-Miocene and Miocene rock units penetrated in the extremely northern offshore Gulf of Suez area. Throughout the pre-Miocene and Miocene, changes in the tectonic pattern, depositional environment, and sediment types indicate different magnitudes and tectonic instability. Based on the available seven dry subsurface composite well logs (GS 9-1, Darag 17-1, GS 24-1, X 80-1, GS 56-1, Fina Z 80-1A, and GS78-1 wells) besides dipmeter logs, 39 stratigraphic maps (isopach and facies maps) are constructed to show thickness variations, facies changes, and paleogeology of Jurassic (Massajid Formation), Lower Cretaceous (Nubia Formation), Upper Cretaceous (Raha, Abu Qada, Wata, Matulla, and Sudr formations), Lower Miocene (Nukhul, Rudeis, and Kareem formations), and Middle Miocene (Belayim, South Gharib, and Zeit formations) times. Moreover, two cross sections are constructed to show thickness and lateral variations in facies changes and tectonics affecting the area at that time. Despite this, the study area has suitable conditions for hydrocarbon generation and accumulation, the seven wells drilled in the study area are considered to be dry or nonproductive. They are considered to be dry or not productive due to tilting of strata to the SW direction, absence of cap rocks (evaporites and salts) and shale in most parts of the study area (especially in the extremely northern parts), and affecting the area by a large numbers of normal faults due to active and continuous tectonic events on the Gulf of Suez area. These reasons may be aided to the migration of hydrocarbons from the area to outside and to the adjacent oil fields.