Ashraf Roshdi Baghdady

Petroleum hydrocarbons frequently contaminate arid oilfield soils, but remediation is challenging because these soils typically contain little organic matter, retain little moisture, and are exposed to high temperatures, that hinder natural attenuation. This study evaluated indigenous bioaugmentation of an aged crude oil-contaminated sandy soil from the Burgan oilfield in Kuwait, in contrast to exogenous commercial microbial products and to natural attenuation. In a 140-day bench-scale tray study, aged crude oil–contaminated soil from the Burgan oilfield (initial TPH 2.49–4.78%, dry wt.) was treated with an enriched indigenous consortium, a commercial consortium, or no inoculum under controlled moisture, nutrient, and aeration conditions. TPH was quantified as hexane-extractable material, and degradation kinetics were evaluated using a first-order model. A statistical comparison of replicate-derived decay constants (k) was conducted using one-way ANOVA and subsequent post hoc testing. Among the replicated treatments, the indigenous consortium showed the strongest performance. In the low-TPH indigenous group, TPH removal reached 63.8 ± 3.1% and fell below 1% by day 140; at higher starting TPH, removal remained substantial but slower. Commercial inoculation was less effective and more variable, while uninoculated controls showed minimal decline. The decay constant for the indigenous (0.0053–0.0075 day⁻¹) was much higher (p < 0.001) than those in commercial (0.0025 day⁻¹) and natural attenuation (0.0005 day⁻¹). Furthermore, the model fit was robust for indigenous treatments (R² = 0.89–0.91) but weaker for commercial and uninoculated controls. The study findings demonstrate that bioaugmentation utilizing well-adapted indigenous consortia offers a statistically validated and kinetically predictable strategy for TPH remediation in desert soils.

The Cenomanian Bahariya Formation exposed at Gebel El Dist in the Western Desert of Egypt provides valuable surface analogues for evaluating the reservoir quality of subsurface Bahariya sandstones. The formation was analyzed using 27 oriented samples and 91 core plugs from quartz arenite (QA) and quartz wacke (QW) facies. Analyses included XRD, petrography, SEM, helium porosity–permeability, and capillary tests, as well as measurements of pore-throat radii (R) at 35% and 36% mercury saturation. X-ray diffraction analyses reveal a heterogeneous mineral composition dominated by quartz, feldspars, dolomite, pyrite, siderite, goethite, hematite, clay minerals, glauconite, and gypsum. QA displays higher porosity and permeability than QW, along with larger pore radii, and lower specific surface area per unit pore volume (Spv) and per unit grain volume (Sgv). Multivariate regression equations, specific to each facies, were developed to convert standardized XRD mineral percentages directly into pore-system and flow attributes (ϕ, k, r, Spv, Sgv, R35, R36), quantifying capillary-based recovery contrasts between facies. Across both facies, regressions linking mineralogy to ϕ, k, r, Spv, Sgv, R35, and R36 are strong (R² = 0.78–1.00). The established predictive equations provide a low-cost method to estimate reservoir quality from mineralogy alone, enabling rapid screening of Cenomanian Bahariya analogues and similar clastic reservoirs where core data are limited.

This paper presents the integration of Geosciences data for three wells which encountered drilling challenges such as differential and mechanical sticking due to geological complexities. It demonstrates the benefits of integrating all available geoscience data in detecting the drilling hazards, delineating the troublesome zones, and offering a complete solution, including drilling best practices and drilling fluids design based on Geological, Sedimentological, Geomechanical and Petrophysical data analysis. A drilling risk assessment was conducted through an analysis of daily drilling reports for the three wells in the field, meanwhile a Post-drill Geomechanical model was constructed for the same wells using all available data. A Petrophysical analysis of the same wells was completed using wireline data to define the major parameters related to drilling risks such as porosity, permeability, facies changes, formation water salinity and shale volume. A Sedimentological analysis utilized the available information from mud logs, image logs, and core data and cuttings descriptions, to correlate drilling risks with certain lithofacies. This case study considers with the geomechanical model of three wells, including their drilling history, stress/pore pressure models, and rock properties. Additional highlights from the image logs are featured, showing anisotropic bedding plane failure, as well as a comparison of the images to the geomechanical model. This case study concludes the risk and a proposed mitigation strategies that could be implemented to limit the risks posed by high overbalance, clay mineralogy, weak bedding planes and permeable sand layers and to minimize instability when drilling vertical and laterals holes in in this area or similarly complex areas. The pressure surveys revealed the presence of both hydrocarbon and water bearing zones. The pressure gradient was 0.14 psi/ft within the hydrocarbon pay zones, whereas a 0.44 psi/ft pressure gradient confirmed the water bearing zones. The same formation pressure data was utilized to calibrate the pore pressure calculations used for the geomechanical model. All Sedimentological and Petrophysical analyses, along with the post-drill Geomechanical analysis, were utilized to define final solutions for optimum well delivery during drilling, completion, and stimulation Phases. Utilizing the analytics of integrated geoscience data such as sedimentology and petrophysics information, along with geomechanical modeling, can help in understanding the subsurface challenges and propose optimal solutions for optimum well delivery avoiding severe tight spots, differential sticking and pack off, in additions of minimizing the formation damages.

The exposures of the lower member of Um Bogma Formation (Early Carboniferous) in a vast area east of Wadi Baba were studied in six localities. The member is dominated by argillaceous rocks in the western and southwestern occurrences, carbonates in the central sector of the area and sandstones at the east.These rock types, especially the carbonates in Allouga locality, consist of large assemblages of non-radioactive, radioactive and REEs- and base metals- bearing minerals of a mixed allogenic-authigenic and primary-secondary origin. Most of the allogenic minerals were inherited from unaltered and altered precursors in felsic igneous rocks. The results of extensive geochemical studies confirmed varying enrichment of the studied rocks in many trace and rare earth elements as well as base metals. The rocks in Allouga locality and, to a lesser extent, those in Talet Seliem and Abu Zarab have the highest potential as possible resources of these elements. Sequential extraction of Mn, Cu, Fe, Pb, U, Th, Y, La and Dy from five fractions revealed that these elements are exchangeable, bound to carbonates, iron and manganese oxides and organic matter and/or residual. The distributions of trace elements and REEs among the different rock types show variation based on their affinities to specific lithologies. The REEs generally show enriched patterns and negative Eu anomalies. U enrichment in rocks of this member is correlated with the occurrence of several types of uranyl silicate minerals. The co-existence of these minerals reflects variations in the activities of Ca, Mg, Cu and Pb. The hydrothermal activities related to the Red Sea extension were responsible for the oxidation of sulphides, alteration of primary minerals and genesis of Mn oxides, surficial uranyl and REEs mineralisations. Based on the obtained data, certain localities are recommended for future prospecting plans.