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The study is paying attention to the variation of the comparative abundance of naphthalenes, phenanthrenes of aromatic fractions separated from seven different Egyptian crude oils, and were studied by GC–MS to assess the thermal maturity and recognize the organic matter input. Tetramethylnaphthalenes (TeMN), Trimethylnaphthalenes (TMN), Dimethylnaphthalenes (DMN), Methylnaphthalenes (MN) and Naphthalene (N), in addition to Phenanthrene (P), and their mono, di and tri -methyl substituted isomers (MP, DMP and TMP) have been identified. Ratios depending on the differences in the thermal stability of the isomers were studied (MPI, MPr, MNr, DMNr, TMNr). The ratios of β- to α-substituted isomers of both methylnaphthalenes and methylphenanthrenes imply higher thermal maturity of WD1 from Faghur and ND1 from Nile Delta basin compared to the rest samples. WD2 crude oil sample from Faghur basin was found to has high amount of 1,3,7- and 2,3,7-trimethylnaphthalenes (TMN) with (TMNr = 2.16) and high Pristan/Phytane ratio (Pr/Ph = 3.49) compared to WD1 from the same basin suggesting in-reservoir oil mixing. [ABSTRACT FROM AUTHOR]

This research presents an innovative hexagonal dielectric resonator antenna (DRA) with circular polarization and multi-input multi-output (MIMO) characteristics. The DRA consists of two dielectric layers, providing a fractional bandwidth of 9% (4.05 to 4.38 GHz).The antenna ground plane features has an S-shape slot, when coupled with a 50 Ω microstrip line, enables the generation of right-hand circular polarization. To enhance performance, the feed line includes a bandpass filter with a semi-elliptical form, resulting in outstanding selectivity. The proposed design demonstrates a gain of 9.2 dBi and encompasses a 3 dB axial ratio bandwidth of 9.29%. The proposed design is fabricated, and a comparison is made between the simulated and the measured results. Furthermore, the study introduces a MIMO antenna system by combining two filter arrays. The MIMO antenna demonstrates a reasonable port isolation of >25 dB across the operating band with acceptable MIMO parameters. [ABSTRACT FROM AUTHOR]

Abstract This paper aims to evaluate the hydrocarbon potentiality and thermal maturity of the Cretaceous source rocks in Al Baraka oil field in KomOmbo basin, south Egypt. To achieve this aim, geochemical analyses (TOC), Rock eval pyrolysis and vitrinite reflectance measurements (R0) were carried out on the studied rocks. The analytical results of the samples that were collected from five exploratory oil wells revealed that almost Lower Cretaceous formations (Sabaya, Abu Ballas, Six Hills and KomOmbo C, B, A) and Upper Cretaceous formations (Dakhla, Duwi, Quseir, Taref and Maghrabi) are ranged from fair to excellent source rocks for hydrocarbon generation. Oil and gas are mainly the future products of the thermally transformed organic matters within almost samples of the Cretaceous formations, where the Lower and Upper Cretaceous formations contain mixed type II/III and III kerogen besides type II kerogen in KomOmbo (B) and Dakhla formations. The thermal maturity parameters clarified that the Lower Cretaceous formations are belonged to marginally mature (in Sabaya and Abu Ballas formations), whereas the rocks of KomOmbo (B) Formation are mature source rocks and fall in the stage of oil generation and reach to the late stage of oil generation (R0 = 1.25). On the contrary the Upper Cretaceous formations are ranged from immature to marginally mature source rocks and reach only the early stage of oil generation in Maghrabi Formation. This study indicated that there is still a good chance to find oil generated from the Dakhla, Duwi, Maghrabi, Sabaya and Abu Ballas formations if buried in greater depths as well as, KomOmbo B and A intervals which are source rock potentials. [ABSTRACT FROM AUTHOR]

Highlights • Chia Gara Formation is an important oil-source rock in the Kurdistan region, North Iraq. • Chia Gara source rock is presently in peak oil-window maturity. • Chia Gara source rock is considered to be generated and expelled mainly oil. • The oil expulsion began since end of Late Eocene to present-day. Abstract The Late Jurassic-Early Cretaceous Chia Gara Formation is an important oil-source rock in Iraqi Kurdistan region. Chia Gara source rock is characterised by high organic matter and sulphur content with Type II_S kerogen. 1D basin models were integrated with geological information and geochemical data from Chia Gara Fm at four well locations in Kurdistan region, northern Iraq. The models of the burial/thermal history indicate that Chia Gara Fm is presently in the peak-oil generation window and some oil cracked to gas during Late Eocene to Late Miocene time. Onset of oil-generation began during the Middle Paleocene- Early Oligocene (60–30 Ma). Oil was generated during the Late Eocene to Late Miocene (48–9 Ma). The models also suggest that the oil was expelled from Chia Gara source rock during the Late Eocene to Late Miocene (37–9 Ma), with a transformation ratio more than 50%. The high transformation ratio of more than 80% in two wells suggests that the generated oil was cracked to gas during the end of Middle Miocene time and continued to present day. The basin modeling results further suggest that Chia Gara Formation acts as a prolific petroleum-source rock and significant of oil and limited of gas have been generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region. [ABSTRACT FROM AUTHOR]

The Semi-enclosed Suez Gulf records various signals of high anthropic pressures from surrounding regions and the industrialized Suez countries. The sedimentary hydrocarbons have been studied in 6 coastal stations located in the Gulf of Suez. Non-aromatic hydrocarbons were analyzed by GC/FID and GC/MS to assess organic content in surface sediments of Suez Gulf, Egypt depending on alkanes, terpanes and steranes biological markers indicators. The results showed that the hydrocarbons are originated from multiple terrestrial inputs, biogenic, pyrolytic. Several ratios of hydrocarbons indicated the predominance of petrogenic in combination with biogenic hydrocarbons. Al-Attaqa harbor, Suez oil processing company, Al-Nasr Oil Company, AL-Kabanon and EL-Sukhna of Loloha Beach are the main sources of petroleum contamination. [ABSTRACT FROM AUTHOR]

This paper represents the first comprehensive survey and provides important data on PAHs concentration and composition in Alexandria coastal seawater. The compositions of PAHs determined in all samples are to be used as chemical markers for identifying different sources of PAH pollution in the surface seawater of Alexandria coastal area. The quantitative analysis of PAHs showed a concentration ranging from 8970.939 to 1254756.00 ng/L, which exceeds the maximum admissible concentrations of PAHs (200 ng/L) for the water standard of European Union. The calculated diagnostic ratios suggested that the sources of PAHs at the majority of the studied area are derived primarily from pyrogenic sources from incomplete fuel combustion of the boats and vehicle engines with lesser amounts of PAHs contributed from petrogenic sources. Some stations displayed mixed sources in comparison to many other studied marine systems, the PAH concentrations detected at Alexandria area were considered to be higher and pose health risks to aquatic bodies. [ABSTRACT FROM AUTHOR]

The TOC-Rock–Eval pyrolysis and vitrinite reflectance measurements for “15” shale rock samples, as well as, multivariate statistical analysis are discussed to investigate hydrocarbon, source rock characteristics, correlation between the assessed parameters (S1, S2, HI, S1 + S2, QI, BI, PI, TOC) and the impact of changes in the T max and R o % on the assessed parameters in Safir exploratory-1x well in Safir oilfield. The geochemical analysis indicated that the Bahariya Formation is considered to be a poor source rock for oil generation with a low degree of thermal maturation in comparison with the Alam El Bueib and Khatatba Formations. However, Alam El Bueib is found to be a good source rock for oil generation with slightly higher thermal maturation. Interestingly, Khatatba Formation lies within the oil and gas generation window and shows an excellent source rock potential. Based on statistical findings of cluster and factor analysis, the source rocks in the study area are classified into two types corresponding to two different clusters. Cluster I includes Alam El Bueib and characterized by kerogen type II and II/III whereas, cluster II, characterized by kerogen type III, is subdivided into two subgroups (IIa and IIb) and represents Bahariya and Khatatba source rocks. Nonparametric tests ( K -independent samples) between the dataset of 15 samples confirm that the distribution of values from respective parameters exhibits significant difference ( P < 0.05) except for PI and BI. On the other hand, the nonparametric tests (2-independent samples) showed that there is no significant difference ( P > 0.05) in the distribution of HI and QI values indicating that both HI and QI values remain constant with increasing thermal maturity. Unlike TOC and HI, Pearson’s and linear regression analysis indicated a significant correlation between TOC and S2. Nevertheless, two different trends were observed between S1 and S2. Moreover, the R o % and T max were found to be positively correlated. Interestingly, our study showed no significant correlation between HI, QI, BI and thermal maturity (R o % and T max ), while, a good correlation between TOC, S2 and thermal maturity was observed. [ABSTRACT FROM AUTHOR]

The aim of this paper is to define the source rock potential of hydrocarbon generation through the determination of: (1) the quantity of organic matter, (2) present day kerogen types, (3) thermal maturity and (4) source organic matter input and depositional conditions of the source rock from Kareem, Rudeis and Matulla Formations, and Nubia Sandstone in 2 wells namely GH 376-1 and GH 404-1 throughout pyrolysis, vitrinite reflectance measurements and gas chromatographic analyses. The results suggest that Kareem and Rudeis source rocks have poor to good generating potential to generate both gas and oil at optimum maturity, Matulla source has a very good while Nubia has poor generating potential to generate both oil and gas at optimum maturity. The organic matter of Kareem, Rudeis and Nubia source rocks was deposited in marine environment under reducing conditions, while Matulla Formation deposited in transition environments and tends to be of terrestrial rather than marine sources. [ABSTRACT FROM AUTHOR]

Oil–oil and oil–source rock correlations are used in this study in order to achieve their relationship, depositional environments and diagenetic processes in the source rocks. Three oil samples and source rock hydrocarbon extracts were analyzed using relative geochemical analyses, and gas chromatography–mass spectrometry are used for this purpose. The results revealed that the extracts of the Alam El Bueib and Khatatba formations are derived from mixed organic sources in which terrestrial dominates marine sources, and deposited in transitional environments under less anoxic conditions. The extracts of Bahariya formation are derived from mixed marine inputs with a limited terrestrial contribution. The Alam El Bueib oil shows more contribution of terrestrial than marine sources. Also, a genetic close relation between them supported the indigenous mixed source of Alam El Bueib oil which related to different sources including the Khatatba, Alam El Bueib and Bahariya formations. Accordingly, the Alam El Bueib formation can be considered as an important source for petroleum generation in the Northern Western Desert. [ABSTRACT FROM AUTHOR]

The present work deals with the identification of the potential and generating capability of oil generation in the Jurassic source rocks in the Salam-3x well. This depending on the organo-geochemical analyses of cutting samples representative of Masajid, Khatatba and Ras Qattara formations, as well as, representative extract samples of the Khatatba and Ras Qattara formations. The geochemical analysis suggested the potential source intervals within the encountered rock units as follows: Masajid Formation bears mature source rocks and have poor to fair generating capability for generating gas (type III kerogen). Khatatba Formation bears mature source rock, and has poor to good generating capability for both oil and gas. Ras Qattara Formation constituting mature source rock has good to very good generating capability for both oil and gas. The burial history modeling shows that the Masajid Formation lies within oil and gas windows; Khatatba and Ras Qattara formations lie within the gas window. From the biomarker characteristics of source rocks it appears that the extract is genetically related as the majority of them were derived from marine organic matters sources (mainly algae) deposited under reducing environment and take the direction of increasing maturity and far away from the direction of biodegradation. Therefore, Masajid Formation is considered as effective source rocks for generating hydrocarbons, while Khatatba and Ras Qattara formations are the main source rocks for hydrocarbon accumulations in the Salam-3x well. [ABSTRACT FROM AUTHOR]

The objective of this study is to assess the organic material for petroleum potential and characterize the relationships between organic material, thermal maturity, and the depositional environments. This is done using “14” samples from the shales of the Dakhla and Duwi formations in Abu Tartur area. The samples have been analyzed using the geochemical method of Rock–Eval pyrolysis. The analysis shows that the total organic carbon content lies between 0.56 and 1.96 wt%. It also shows that kerogen is a mixture of type II and III that is dominant, and is deposited in the shallow and restricted marine environment under prevailing reducing conditions. This type of kerogen is prone to oil and oil/gas production. The geochemical diagrams show that all the studied samples have good thermal maturation. The Dakhla and Duwi formations which have been divided into all zones are mature (have T max over 435 °C), and have organic carbon content located at the oil window ( T max between 435 and 443 °C). [ABSTRACT FROM AUTHOR]

The present work aims to evaluate the nature and origin of the source rock potentiality of subsurface Middle Jurassic and Lower Cretaceous source rocks in Melleiha G-1x well. This target was achieved throughout the evaluation of total organic carbon, rock Eval pyrolysis and vitrinite reflectance for fifteen cutting samples and three extract samples collected from Khatatba, Alam El Bueib and Kharita formations in the studied well. The result revealed that the main hydrocarbon of source rocks, for the Middle Jurassic (Khatatba Fm.) is mainly mature, and has good capability of producing oil and minor gas. Lower Cretaceous source rocks (Alam El Bueib Fm.) are mature, derived from mixed organic sources and have fair to good capability to generate gas and oil. Kharita Formation of immature source rocks originated from terrestrial origin and has poor to fair potential to produce gas. This indicates that Khatatba and Alam El Bueib formations take the direction of increasing maturity far away from the direction of biodegradation and can be considered as effective source potential in the Melleiha G-1x well. [ABSTRACT FROM AUTHOR]

In this study, we apply geochemical and statistical analyses for evaluating source rocks in Ras Gharib oilfield. The geochemical analysis includes pyrolysis data as total organic carbon (TOC%), generating source potential (S2), production index (PI), oxygen and hydrogen indices (OI, HI) and (Tmax). The results show that the Cretaceous source rocks are poor to good source rocks with kerogen of type III and have the capability of generating gas while, the Miocene source rocks are good to excellent source rocks with kerogen of type III–II and type II and have the capability of generating oil and gas. The analyzed data were treated statistically to find some factors, clusters, and relations concerning the evaluation of source rocks. These factors can be classified into organic richness and type of organic matter, hydrocarbon potentiality and thermal maturity. In addition, cluster analysis separated the source rocks in the study area into two major groups. (1) Source rocks characterized by HI >300 (mg/g), TOC from 0.76 to 11.63 wt%, S1 from 0.44 to 9.49 (mg/g) and S2 from 2.59 to 79.61 (mg/g) indicating good to excellent source rocks with kerogen of type III–II and type II and are capable of generating oil and gas. (2) Source rocks characterized by HI <300 (mg/g), TOC from 0.31 to 2.07 wt%, S1 from 0.17 to 1.29 (mg/g) and S2 from 0.31 to 3.34 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Moreover, Pearson’s correlation coefficient shows a strong positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. [ABSTRACT FROM AUTHOR]

The present work aims to evaluate the organic geochemistry of the crude oils recovered from Ashrafi and GH oilfields within the Gulf of Suez to assess and investigate oil characterization, maturation, source depositional environments and oil families. The saturated hydrocarbons were determined by gas chromatography and gas chromatography/mass spectrometry. Pristane/phytane, isoprenoids/n-alkanes, CPI, homohopane, diasteranes, gammacerane index, C29 20S/20S+20R, C29/C30 hopane and Ts/Tm are determined. The results suggest that the studied crude oils belong to marine oil and are characterized by high level of maturation and sourced mainly from organic matters of marine origin with few terrestrial inputs. [ABSTRACT FROM AUTHOR]

[Display omitted] • The shales of the Kom Ombo Formation are organic-rich sediments, with TOC value of up to 6.61 wt%. • The organic facies are predominantly of Types II and II/III kerogen. • Kom Ombo shales were deposited in a marine under anoxic environmental conditions. • The shales reached peak oil-window and generated commercial amounts of oil. This study uses organic geochemical and petrographic analyses to characterise the organic-rich shales from the Lower Cretaceous Kom Ombo Formation in the Kom Ombo Basin. The overall results show that the Kom Ombo shales are considered to have good petroleum source rock potential with total organic carbon (TOC) content > 1 wt% and hydrocarbon yields of up to 27.62 mg hydrocarbons/g rock. Based on lipid biomarker ratios and carbon isotopes, the Kom Ombo shale contains a blend of organic matter derived primarily from algal marine and other aquatic organic matter, with some terrigenous land plants, deposited under anoxic conditions. These findings of organic matter (OM) input and depositional conditions are consistent with the high TOC content of up to 6.61 wt% and mainly Types II and II/III kerogen, with small amounts of Type III kerogen, thus yielding both oil and gas, with oils of high to low wax contents. Geochemically, the dominance of oil generation potential is in agreement with the presence of considerable concentration of fluorescent liptinite macerals. The chemical and optical maturity results show that the majority of the examined Kom Ombo shale samples have entered the main stage of oil generation, exhibiting a range of early-mature to late-mature. Therefore, as highlighted in this study, the oil generation potential of the Kom Ombo shales may represent a good opportunity for future conventional petroleum exploration. [ABSTRACT FROM AUTHOR]

Rock-Eval pyrolysis/TOC, petrographic, and geochemical data available in the public domain for a total of 296 core and 243 drill cuttings samples from the Albian-early Cenomanian Kharita and Bahariya formations of four main basins, Shushan, Abu Gharadig, Matruh and Dahab-Mireir, were reviewed. This review provides a comprehensive overview to understand the organic richness, type, and thermal maturity of potential source rock intervals within the Kharita and Bahariya formations in northern Egypt by means of burial history modeling and oil-in-place calculations. Geochemical data of both formations confirmed the presence of up to excellent source rocks of varied kerogen types but mainly of Type III (gas-prone) and mixed types II/III. Thermal maturity levels ranged from immature to the early stage of oil window, although some intervals reached the peak oil window in the Abu Gharadig and Shushan basins compared to their counterparts. The depositional paleoenvironment of the Kharita and Bahariya formations is interpreted based on the organic biomarker compounds and palynofacies associations. Generally, both formations in the four basins were interpreted to accumulate in a fluvio-deltaic to marginal marine setting, although the Kharita rock unit was slightly less marine based on the isoprenoids pristane and phytane to nC 17 and nC 18 ratios. The ratio of 22S/(22S + 22R) for the homohopanes C 31 and C 32 of Kharita oils from the Shushan Basin ranged from 0.50 to 0.60, indicating marginally mature to the onset of oil generation. However, common amongst much of the previous studies was the notable differences in organic matter contents, thermal maturity levels and hydrocarbon potential. Environmental and ecological processes, including proximity to shoreline, terrestrial/riverine input, oxygenation levels and water column conditions, are considered the primary drivers that triggered variable amounts of organic carbon accumulation. While differences in thermal maturity levels were attributed to tectonic activities and related structural processes. • Fair to good organic matter-richness in the Bahariya and up to excellent for the Kharita Formation was reported. • The source rock beds within the both formations have variable kerogen types (Type III, II/III and II). • Levels of maturation in both formations were mainly immature to early mature with minor intervals in peak stage of oil window. • The Kharita and Bahariya formations had the highest yield of oil‐in‐place in the Matruh Basin. • Despite the Kharita was less marine than Bahariya, both formations were deposited in fluvio-deltaic/marginal marine settings. [ABSTRACT FROM AUTHOR]

Abstract The Mukalla Formation is one of the important petroleum source rocks in the Jiza-Qamar Basin, Eastern Yemen. In this study, coal, coaly shale and shale samples from three wells (Al-Fatak-1, 16/G-1 and 16/E-1) in the offshore Jiza-Qamar Basin were studied. The organic matter richness, kerogen type, thermal maturity, and petroleum generation potential of the Mukalla organic-rich samples were investigated. The analysed Mukalla source rock samples are potentially rich in organic matter of 1.01–84.40% TOC, ranging from good to excellent source rocks. The Mukalla source rocks primarily contain Types II, II–III and III kerogen, anticipating generating mainly oil and gas. This is generally consistent with the pyrolysis–gas chromatography results and further indicates that the Mukalla source rocks can produce high wax oil and condensate/gas. The thermal maturity parameters reveal the Mukalla source rocks are in mature to late-mature and are capable of generating oil and wet gas at the present time. In addition, this study was integrated the geochemical, geo-thermal and geological data in term of basin modeling study to simulate the timing of hydrocarbon generation and expulsion from the Mukalla deltaic source rocks. The basin model results indicate that the oil generation commenced during the late Eocene to late Oligocene, with a conversion ratio of 10–50 TR%. Furthermore, based on TRs of more than 50%, the most of oil was expelled along the micro-fracturing of the Mukalla source rocks and then trapped in the Mukalla Formation itself during the latest Oligocene and continued to present-day. Highlights • The Mukalla Formation in the offshore Jiza-Qamar Basin is considered as a deltaic source rock. • Basin models were constructed from three wells in the offshore Jiza-Qamar Basin. • Mukalla source rocks reached the late oil-window in the present-day. • The oil was generated during late Eocene to late Oligocene, with a conversion ratio of 10–50%. • The oil was then expelled along the micro-fracturing of the Mukalla source rocks. [ABSTRACT FROM AUTHOR]

A comprehensive set of organic and inorganic geochemical proxies, clay mineralogy, and molecular fossils are presented from two biostratigraphically well-dated oil shale horizons of Egypt, within the Upper Cretaceous Duwi and Dakhla formations. The studied oil shales were deposited within intracratonic sedimentary basins in a broad northern African epeiric sea. Calcareous nannofossil biostratigraphy indicates that the oil shales range from early to late Maastrichtian in age, covering nannofossil zones UC18, UC19, and UC20. The oil shales contain smectite and kaolinite as the main clay minerals that formed by weathering of precursor basement rocks. The relative abundances of clay minerals and several geochemical proxies (e.g. C-value, CIA, Ga/Rb, Rb/Sr and Sr/Cu), along with the occurrence of warm-water nannofossil taxa, demonstrate that the Maastrichtian oil shales accumulated under a warm, arid to humid greenhouse climate during a general Maastrichtian cooling trend. This episode of oil shale deposition in Egypt coincided with the first potential imprint of the global warming, that has been recorded during early-to-late Maastrichtian times (~70.6–67.7 Ma). Elevated eolian terrigenous input was recorded within the Duwi Formation oil shales, shown by high Ti/Al, Si/Al, Zr/Al and low La/Lu ratios. The Duwi Formation environment was characterized by enhanced salinity and a stratified water column, compared to that of the Dakhla Formation, shown by elevated values of the gammacerane index, tetracyclic terpane, β‑carotene and Sr/Ba ratio. The CaCO 3 content and carbonate/siliciclastic ratio indicate that the Dakhla Formation oil shales were deposited during a relative sea-level rise in a deeper marine setting than the Duwi Formation oil shales. The data further imply a wind-driven upwelling scenario of nutrient input s that simulated primary production and increased organic matter fluxes. Thus, paleoclimate and paleoceanography had a considerable impact on organic matter enrichment. [ABSTRACT FROM AUTHOR]