Naira M. Lotfy

Egyptian Petroleum Research Institute

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Mohamed M. El Nady

Egyptian Petroleum Research Institute

Mohammed Hail Hakimi

Kazan Federal University

Sherif Farouk

Egyptian Petroleum Research Institute

Fatma S. Ramadan

Zagazig University

Afikah Rahim

University of Technology Malaysia

Fayez Ahmad

Appalachian State University

Tamer E. Hamed

Egyptian Petroleum Research Institute

Doaa A. Mousa

Egyptian Petroleum Research Institute

Chang Samuel Hsu

Florida A&M University - Florida State University College of Engineering

Aref Lashin

King Saud University

Cooperative Institutions

Egyptian Petroleum Research Institute

King Saud University

Taiz University

Suez University

Hashemite University

Zagazig University

Indian Institute of Management Lucknow

Benha University

University of Malaya

All India Institute of Medical Sciences

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Geochemical characteristics and genetic types of Ordovician tight gas in the Risha Gas Field, Eastern Jordan based on carbon and hydrogen isotope compositions

Marine and Petroleum Geology (2022)

Naira M. Lotfy Abdelrahman Qteishat Sherif Farouk Fayez Ahmad Khaled Al‐Kahtany

Propane

Natural gas field

Carbon fibers

Isotopic signature

10.1016/j.marpetgeo.2022.105810

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Citations (5)

Upgrading of silica sand using chemical leaching process for industrial application at Wadi El Dakhal area, Egypt

Egyptian Journal of Petroleum (2025)

Abd El‐Aal M. Gaber Tamer E. Hamed Yousef A. Selim Naira M. Lotfy

Silicon dioxide

Foundry

Dissolved silica

10.62593/2090-2468.1054

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Biomarker and isotopic characteristics of Miocene condensates and natural gases, West Delta deep marine concession, Eastern Mediterranean, Egypt

Scientific Reports (2024)

Naira M. Lotfy Sherif Farouk Mohammed Hail Hakimi Fayez Ahmad Tamer El Shennawy

Abstract The Western Delta Deep Marine Concession (WDDM) in the Eastern Mediterranean Sea is one of northern Africa's most recent petroleum-potential regions for gas and condensate exploration. The present study aims to determine the characteristics of the 15 natural gases and 5 associated condensate samples, using molecular compositions and isotopes from the Miocene reservoir rocks in the various wells located in the WDDM. The results of this study are also used to determine the gas-condensate correlation for their probable source rocks as well as the methane-generating mechanisms (i.e., thermogenic or microbiological). Results highlighted in this research reveal that most of the natural gases in WDDM are mainly thermogenic methane gases, with small contributions of biogenic methane gases that were generated from mainly mixed sources, with a high sapropelic organic matter input for biogenic gases. The thermogenic methane gases were formed from secondary oil and oil/gas cracking at the high maturity stage of the gas window. The biogenic gases are also contributed to the Miocene reservoirs, which are formed from the primary cracking of kerogen at low maturity stage by the action of CO 2 bacterial reduction. In addition, the saturated and aromatic biomarker results show that the condensate samples were generated from clay-rich source rocks. This source unit of the Miocene condensates were deposited in a fluvial deltaic environmental setting, containing mixed kerogen type II/III and accumulated during the Jurassic–Cretaceous, as evidenced by the age dating indicators. The properties of the natural gases and associated condensates in the Miocene reservoir rocks suggest that most of the thermogenic methane gases, together with the condensate, are derived primarily from mature Jurassic–Cretaceous source rocks and formed by secondary oil and oil/gas cracking at the gas generation window, as demonstrated by the 1-D basin modelling results highlighted in the prior works. Therefore, most of the natural gases in WDDM are non-indigenous and migrated from more mature Jurassic–Cretaceous source rocks in the nearby Northern Sinai provinces or the deeper sequences in the offshore Nile Delta provinces.

Diamondoid

Abiogenic petroleum origin

10.1038/s41598-023-50418-4

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Upper Cretaceous-Paleocene Unconventional Oil Shales in Egypt and Jordan: Insights into Organic Geochemistry

Geomicrobiology Journal (2022)

Sherif Farouk Naira M. Lotfy Fayez Ahmad Nagla M. Khalil Khitam Alzughoul

The present paper investigates the unconventional hydrocarbon potential and characteristics of Campanian–Paleocene oil shales at five outcrop sections in central Egypt and Jordan. One-hundred and seven outcrop samples were analyzed for their content of total organic carbon and total sulfur. Twenty-four samples were selected for further geochemical treatment, including Rock-Eval pyrolysis, and six samples were subjected to molecular analyses using gas Chromatography (GC) and Gas Chromatography-Mass Spectrometry (GC-MS). The distribution of aliphatic hydrocarbon biomarkers indicated that most of the organic matter in the studied samples had a marine origin under anoxic to suboxic conditions. The results indicated that the upper Campanian Duwi Formation in the Quseir area of central Egypt and the Maastrichtian-Paleocene Muwaqqar Chalk Marl (MCM) Formation in the Lajjun area of central Jordan had a relatively high hydrocarbon generating potential with a TOC content of up to 20%wt of immature Type I/II kerogen. Biomarker studies of the investigated formations revealed that the origin of the organic matter is marine algae with a minor contribution of bacterial biomass. The terrigenous/aquatic ratio (TAR) indicated the marine origin of the Jordanian organic matter (MCM and Al-Hisa Phosphorite Formation formations). By contrast, the Duwi Formation in Egypt and the Amman silicified limestone Formation in the Umm Qais section of Jordan showed that these localities were affected by a more terrigenous influx to the principal marine organic matter compared with other rock units. In addition, in the Abu Tartur section the Duwi Formation showed a significant microbial reworking of organic matter reducing the actual amount of organic matter and its hydrocarbon generating potentiality. Clear correlations between nature and the preservation of organic matter is noticed, where the high organic matter mainly occurs in regional paleo-upwelling areas, strongly related to an increase in marine phytoplanktonic/algal and bacterial productivity.

Terrigenous sediment

Organic geochemistry

Marl

Outcrop

10.1080/01490451.2022.2060388

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Citations (3)

Mineralogical and geochemical characteristics of the Paleozoic source rocks, Akkas gas field, Western Desert of Iraq: Implications for their origin, maturation and Ordovician-Silurian transition

Marine and Petroleum Geology (2020)

Ibrahim Mohammed Sherif Farouk Hassan Baioumy Naira M. Lotfy Aboosh H. Al-Hadidy

Illite

10.1016/j.marpetgeo.2020.104432

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Citations (23)

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

Energy Sources Part A Recovery Utilization and Environmental Effects (2015)

Mahmoud Hammad Mohamed M. El Nady Fatma S. Ramadan Naira M. Lotfy

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.

10.1080/15567036.2012.717165

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

Petroleum Science and Technology (2018)

Mohamed M. El Nady Fatma S. Ramadan Mahomoud M. Hammad Doaa A. Mousa Naira M. Lotfy

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.

10.1080/10916466.2018.1465978

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Citations (1)

Review for "Geochemical characteristics and genetic types of crude oils from a variety of geological reservoir rocks (Cretaceous–Palaeogene) in the Melut Basin, southern Sudan based on biomarker and carbon isotope composition"

Naira M. Lotfy

Paleogene

10.1002/gj.4824/v1/review2

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Geochemical characteristics and thermal maturity modelling of Alam El Bueib/Kharita in the Tut Oil Field, Shushan Basin, North Western Desert, Egypt

Frontiers in Scientific Research and Technology (2024)

Hadeer A. Hassan Sherif Kharbish Saada Saada Naira M. Lotfy

The main goal of this study is determining the source rock characteristics and petroleum generative potentiality of the Lower Cretaceous formations in the Tut Oil Field. The present work has employed multiple analytical techniques, including TOC, rock-eval pyrolysis, organic petrography, and palynofacies analysis. The geochemical analyses suggested that the Kharita Formation is immature source rock (with Ro= 0.52) with poor hydrocarbon potentiality to generate gas (type III and IV kerogen). The AEB Formation is ranging from immature to mature source rocks (with Ro= 0.52-0.67) and has poor to very good generating capability for producing gas and mixed oil/gas (III and II/III). Conversely, the organic petrographical analysis indicates that all samples of AEB Formation are of type II, with a high abundance of liptinite. Along with, Three palynofacies associations have been identified by the palynofacies study in the AEB Formation: Palynofacies association-A is dominated by the phytoclasts group, ranging from 54 to 90%, with significant amounts of amorphous organic matter (AOM) (6-38%), Palynofacies association-B reveals a high abundance of phytoclasts (61-98%) compared to palynomorphs and AOM, and Palynofacies association-C displays a dominance of AOM with significant amounts of phytoclasts. Ultimately, basin modelling was utilised to incorporate the results of geochemical tests in order to improve our understanding of the hydrocarbon production process from AEB/Kharita fms. According to this model, AEB Fm reached the early mature stage with a transformation ratio of less than 10% TR and no indications of generation or expulsion, while Kharita Fm are still in the immature stage.

Desert (philosophy)

10.21608/fsrt.2024.273633.1120

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Biomarker characteristics of organic shale beds of Alam El Bueib Formation in Tut Oil Field, Shushan Basin, North western Desert, Egypt: Insights from oil/source rock correlation

Egyptian Journal of Petroleum (2024)

Hadeer A. Hassan Sherif Kharbish Saada Ahmed Saada Fatma S. Ramadan Hoda A. Mohammed

The organic shale beds in the Alam El Bueib (AEB) are thought to provide an excellent source for producing hydrocarbons. Consequently, defining the role of the AEB Formation in hydrocarbon generation in the Tut Oil Field is the primary objective of this research. This research presents an analysis of biomarkers in a set of Tut Oil Field AEB extracts and oils to appreciate the basin's hydrocarbon exploration and development. AEB shales have low Pr/Ph ratios (0.5–0.83), low to high values of C22/C21 tricyclic terpanes, low values of C19/C23 tricyclic terpanes, high values of C31R homohopanes /C30hopanes, and high concentration of regular steranes C27 decode that the OM was primarily derived from marine algae/ bacterial derived organic matter, along with small amounts of land plant formed in reducing environment. In addition, the maturity-related parameters display values ranging from low to high. The oils recovered from Bahariya and AEB reservoirs have higher Pr/Ph ratios, high values of tricyclic terpanes (C22/C21) decode that the OM was primarily derived from marine algae/ bacterial derived organic matter, and an elevated concentration of C29 steranes interpret that the OM was primarily derived from mixed marine algae/ landplant derived organic matter formed in suboxic environment. The maturity-related parameters display high maturity values. Based on various biomarker criteria, the hierarchical cluster analysis (HCA) of crude oils and AEB extract reveals no genetic relationship between the AEB source rock and the studied oils.

Organic geochemistry

10.62593/2090-2468.1019

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