Wettability is the fundamental parameter that influences the productivity of hydrocarbon reservoirs. The knowledge of this regarding shale formation is yet inadequate; thus, detailed analysis is essential for successful development of such reservoirs. The Early Cretaceous Sembar formations in the Lower Indus Basin, Pakistan, is considered as the key target for energy exploration; however, it exhibits large uncertainties due to the lack of data availability. Sembar shales hold significant hydrocarbon volumes rich in organic content; however, prior to this, no comprehensive research has been conducted to quantify the wetting behavior of these shales. Thus, precise information about the wetting behavior of Sembar shale formations is essential, as it is influenced by many factors. Therefore, in this study, we examined the wettability of Sembar shale samples by performing a suit of contact angle (CA) measurements. The CA measurements on shale samples were performed using different salt types (NaCl, KCl, MgCl₂, and Reef Salt) and concentrations of 0.1 M and 0.5 M under ambient pressures and varying temperatures (25-50 °C). The CA was measured via air-brine and air-oil under prevailing pressure and temperature conditions. Subsequently, the sample morphology and surface topography were examined via field emission scanning electron microscopy and atomic force microscopy, respectively. The mineral compositions were obtained via X-ray diffraction studies. The results clearly show that the Sembar shale possesses a mixed wetting behavior. Under dry surfaces, they have large affinity to oil and deionized water in which the droplet spreads quickly on the sample surfaces. Conversely, the samples aged with n-decane and NaCl brines exhibited higher CAs than the untreated samples. Additionally, the CA measured by changing temperatures led to an increase for all brine droplets; the CA further increased as the concentrations of salts increased from 0.1 to 0.5 M. We then discussed the possible reasons for the discrepancy in CA values due to temperature changes and brine concentrations. Moreover, the CA was measured corresponding to the surface roughness from which it appears that it merely affects the wettability of these shale samples. However, the present study results lead to an improved understanding of the wettability of Sembar shale of the Lower Indus Basin in Pakistan.

We have studied geochemical characteristics, mineralogy and origin of the manganese deposits in Bela ophiolitic complex. Geochemical investigation was conducted in order to discuss the elemental correlations and to infer the probable origin of manganese deposits in Bela ophiolites. Ore microscopy was conducted to identify different manganese minerals and their paragenesis. Psilomelane and braunite were found to be the major ore minerals. Mineral paragenesis sequence as observed was braunite forming first. Psilomelane formed in later stages because it has been found that psilomelane is altering the braunite. Magnetite was observed as a secondary mineral as vein filling and cutting through both the braunite and psilomelane, therefore, younger than the psilomelane and braunite. The gangue minerals observed in the studied samples were quartz, cryptocrystalline silica and calcite. The correlations among different major and trace elements showed diversity of relations. MnO showed negative correlation with Fe₂O₃ (− 0.73), Si₂O (− 0.27), positive correlation with Al₂O₃ (0.54), TiO₂ (0.36), MgO (0.22), Pb (0.23), Ni (0.07), Cr (0.12), and no correlation was established with Zn, Cu, Co. Binary diagram of Si versus Al and ternary discrimination diagrams of Fe–(Ni + Co + Cu) × 10–Mn and Ni–Zn–Co showed hydrothermal-diagenetic-type deposits. Furthermore, the present study suggests that the enriched manganiferous fluid during its upward movement within the Tethys oceanic crust near spreading center started precipitating Mn along with Fe on the sea floor. Later on, these manganese minerals were obducted on land between Indian plate and Helmond block of Eurasian plate in existing position accompanying pillow basalt and pelagic sediments.

Significant amounts of hydrocarbon resources are left behind after primary and secondary recovery processes, necessitating the application of enhanced oil recovery (EOR) techniques for improving the recovery of trapped oil from subsurface formations. In this respect, the wettability of the rock is crucial in assessing the recovery and sweep efficiency of trapped oil. The subsurface reservoirs are inherently contaminated with organic acids, which renders them hydrophobic. Recent research has revealed the significant impacts of nanofluids, surfactants, and methyl orange on altering the wettability of organic-acid-contaminated subsurface formations into the water-wet state. This suggests that the toxic dye methylene blue (MB), which is presently disposed of in huge quantities and contaminates subsurface waters, could be used in EOR. However, the mechanisms behind hydrocarbon recovery using MB solution for attaining hydrophilic conditions are not fully understood. Therefore, the present work examines the impacts of MB on the wettability reversal of organic-acid-contaminated Khewra sandstone samples (obtained from the outcrop in the Potwar Basin, Pakistan) under the downhole temperature and pressure conditions. The sandstone samples are prepared by aging with 10^-2 mol/L stearic acid and subsequently treated with various amounts of aqueous MB (10-100 mg/L) for 1 week. Contact angle measurements are then conducted under various physio-thermal conditions (0.1-20 MPa, 25-50 °C, and salinities of 0.1-0.3 M). The results indicate that the Khewra sandstone samples become hydrophobic in the presence of organic acid and under increased pressure, temperature, and salinity. However, the wettability changes from oil-wet to preferentially water-wet in the presence of various MB solutions, thus highlighting the favorable effects of MB on EOR from the Khewra sandstone formation. Moreover, the most significant change in wettability is observed for the Khewra sandstone sample that was aged using 100 mg/L MB. These results suggest that injecting MB into deep underground Khewra sandstone reservoirs may produce more residual hydrocarbons.

This study proposes economic evaluation of CO₂ geological storage with enhanced oil recovery. The procedures consider capital expenditures and operating costs of infrastructures and revenues from oil recovery and carbon tax credits. Extensive CO₂ geological storage with enhanced oil recovery simulations was conducted to determine the most promising scenario among cases, where miscibility was controlled by the addition of liquefied petroleum gas. The addition of liquefied petroleum gas into a CO₂ injection stream can accelerate reduction of oil viscosity, interfacial tension, and oil density, which cause improved displacement efficiency. The larger was the amount of liquefied petroleum gas injected, the greater was the miscibility due to minimum miscibility pressure reduction, resulting in higher oil recovery and less CO₂ sequestration. Although liquefied petroleum gas addition enhances the performance of CO₂ enhanced oil recovery, economic analysis should be conducted for CO₂ geological storage with enhanced oil recovery due to the higher price of liquefied petroleum gas than that of CO₂. Net present value decreased from liquefied petroleum gas mole fraction of 0–2% and started to increase from mole fraction 2–13% due to the miscibility effect. Then, net present value started to decrease, because the purchasing and injecting prices of the required liquefied petroleum gas exceeded that of the oil produced. Economic evaluation showed that addition of 13% liquefied petroleum gas was the most promising scenario, with a net present value of 91 MM$. Thus, we confirmed an optimum liquefied petroleum gas concentration in the CO₂ geological storage with enhanced oil recovery process.