Minerals

The CO₂ absorption rate and total uptake by MgO aqueous suspensions were investigated in batch experiments by systematically varying MgO concentrations (0.5–5 wt.%), CO₂ flow rates (0.5–2 L/min), temperatures (278–363 K), NaCl salinities (0–7 wt.%), Na₂SO₄ and K₂SO₄ concentrations (0–10.5 wt.%), and gas–liquid mixing systems (pipe outlet and porous stone sparger). Results show that temperature strongly controls the carbonation process: increasing temperature above 303 K consistently reduced both the CO₂ absorption rate and the total CO₂ uptake due to the destabilization of metastable Mg(HCO₃)₂ solutions and accelerated precipitation of less soluble hydrated magnesium carbonates. Under optimal low-temperature conditions (278–283 K, 1–1.5 wt.% MgO, sparger mixing, pure system), the average capture efficiency reached ≈ 35%, with maximum peaks over 70% and total CO₂ uptakes of ≈ 12–17 L. Adding NaCl at typical seawater levels (3.5–7 wt.%) slightly increased CO₂ uptake at temperatures above 323 K. Sulfate ions (Na₂SO₄ and K₂SO₄) were found to enhance the absorption rate at low concentrations (<2 wt.%) but reduce it at higher levels, with no significant impact on the total CO₂ uptake observed in this study. Using a CO₂ sparger significantly improved gas–liquid contact, achieving average CO₂ capture efficiencies above 70% at low temperatures, compared to <20% with simple pipe bubbling. A direct comparison with Ca(OH)₂ aqueous carbonation confirmed that, despite its lower solubility and slower kinetics, MgO can outperform Ca-based systems under specific conditions. These results provide practical experimental benchmarks and process guidance for designing Mg-based aqueous carbonation systems, including applications that use brines, industrial wastewater or seawater.

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 study provides the first comprehensive characterization and classification of organic microfacies within the globally significant Jurassic hydrocarbon source rocks of Iraqi Kurdistan. This study aims to resolve the knowledge gap in the Jurassic source rocks of northern Iraq by establishing the first organic microfacies classification scheme, utilizing an integrated petrographic and geochemical approach to reconstruct the regional paleoenvironmental evolution and confirm the source rock’s petroleum potential. The Middle–Late Jurassic Sargelu, Naokelekan, and Barsarin formations were investigated using samples from the Mangesh-1 and Sheikhan-8 wells. Using cluster analysis, we identified five distinct organic microfacies (A–E). Microfacies A (highly laminated bituminite), B (laminated/groundmass bituminite), C (laminated rock/lamalginite), and D (massive organic-matter-rich) show the highest hydrocarbon generation potential. The findings reveal a clear paleoenvironmental evolution: the Sargelu Formation was deposited in anoxic open marine conditions (microfacies C, D); the Naokelekan Formation represents a progressively restricted silled basin with intense anoxia leading to condensed sections dominated by microfacies A, which shows the highest source rock potential; and the Barsarin Formation reflects increasing restriction and hypersalinity, showing diverse microfacies (B, C, D, E) that captured variations in marine productivity and terrigenous influx. Principal component analysis (PCA) quantitatively modeled these paleoenvironmental gradients, aligning the distinct organic microfacies and their transitions with conceptual basin models. Geochemical analysis confirms that the organic matter is rich, predominantly Type II kerogen, and thermally mature, falling within the oil window. The presence of solid bitumen, both in situ and as evidence of migration (microfacies E), confirms effective hydrocarbon generation and movement. This integrated approach confirms the significant hydrocarbon potential of these Jurassic successions and highlights the critical role of specific organic microfacies in the region’s petroleum system, providing crucial guidance for future hydrocarbon exploration in northern Iraq.