This study provides a comprehensive assessment of the shale gas potential of the Middle Jurassic Khatatba Formation in the Obaiyed Field, Western Desert, Egypt, by integrating geological, petrophysical, geochemical, and geomechanical datasets into a unified workflow. The multidisciplinary approach allows for the identification of shale gas "sweet spots" and addresses critical operational risks associated with drilling and completion. Petrophysical evaluation indicates heterogeneity, with total porosity ranging from 6 to 12%, effective porosity between 4 and 8%, shale volume often exceeding 40% but locally decreasing below 30%, and permeability within 0.01-0.1 mD. Gas storage capacity is enhanced at depths greater than 3800 m, where free gas contents are significant and adsorbed gas reaches 1.5-2.0 cm³/g in Total Organic Carbon (TOC)-rich intervals. Geochemical analysis confirms that the Upper Safa Member is thermally mature within the gas window, with TOC averaging ~4 wt% and mixed Type II-III kerogens, while traces of CO₂ (0.8-2.0 mol%) and H₂S (25-80 ppm) raise concerns about casing corrosion and necessitate careful material selection. Geomechanical results reveal brittle intervals with high Young's modulus and low Poisson's ratio, fracture gradients ranging from 25 to 30 MPa/km, and maximum horizontal stress (σHmax) typically 1.2-1.5 times the minimum horizontal stress (σhmin), defining a narrow safe mud weight window. Seismic inversion delineates TOC-rich, low-impedance intervals as optimal drilling targets, while fault-bounded compartments highlight both opportunities for hydrocarbon trapping and risks of reservoir compartmentalization. The integration of reservoir quality (RQ) and completion quality (CQ) with stress and pressure profiles enables optimized well orientation and trajectory planning, particularly recommending horizontal wells perpendicular to σHmax in the lower Upper Safa Member. This integrated evaluation confirms the Upper Safa Member as the most promising shale gas target within the Khatatba Formation and establishes a transferable workflow for unconventional reservoir development worldwide.

The capacitance-resistance model (CRM) is a widely-used model for predicting well production rates because it requires the estimation of only a small number of parameters to describe production wells and the connectivity between injection and production wells. However, CRM parameters are not inherently spatially constrained, which can lead to unnatural results. In this research, we conducted spatially continuous regularization of CRM parameters and investigated how it affected model accuracy. A related goal was to investigate how this regularization improved the spatial interpolation of CRM coefficients. For regularization, we considered CRM parameters as values for a spatially continuous function, implemented this function using a neural network, and fitted it using production history data. We employed two benchmark datasets—the egg and Costa datasets—to compare two models: the unconstrained conventional CRM and the proposed spatially regularized CRM. We concluded that the spatially regularized CRM yielded accuracy close to that of the conventional CRM; however, it provided a more interpretable spatial distribution of the CRM parameters.

Oil reservoirs subjected to a gas recovery technique are commonly challenged by early gas break-throughs affecting the production rate. Foam is injected to block and divert gas to reservoir sections, however, achieving this mechanism requires stable foam to withstand extreme reservoir conditions, such as temperature, pressure and salinity. In this work, synergy actions between aminopropyltriethoxysilane doped SiO₂ nanoparticles (NPs) and MFomax were investigated on rheology, interfacial tension (IFT), wettability, foam stability and quality to reduce gas mobility and enhance oil recovery (EOR). The formulation was guided by optimization, and the foam studies were carried out at optimum concentrations. Core-flood equipment was used to assess the gas mobility reduction factor (MRF) and EOR. From the findings, the foamability of the nanofluid is primarily governed by synergy action between the NPs and MFomax due to significant R² value (0.9; p < 0.05). Presence of NPs in the formulation resulted in good fluid properties such viscosity and IFT. The nanofoam stability has improved tremendously to 119% relative to MFomax foam. According to the IFT and contact angle, the detachment energy of the NPs (1.4 × 10⁸ eV) is higher than 1 eV suggesting strong adsorption at aqueous interface leading to foam stability. The nanofoam reached a maximum of 50 MRF, while MFomax was below 40 MRF. Subsequently, all the foam descended to lower quality regions around 5 PVI due to the change in foam morphology. Furthermore, the EOR recorded by nanofoam demonstrates a 7% increase on top of MFomax recovery factor. Thus, it can be deduced that the synergy of SiO₂ NPs with MFomax offer several benefits in improving the foam stability, quality, MRF and EOR.

Upgrading heavy crude oil remains one of the most critical and technically demanding processes in the petroleum industry, primarily due to the inherently poor quality of the various types of crude oil and the complexities associated with their transport and refining. This study investigates the impact of a nano-fluid—composed of aluminum oxide nanoparticles dispersed in a kerosene solvent and stabilized with the surfactant sodium dodecylbenzenesulfonate—on enhancing the quality of crude oil extracted from an East Baghdad field. This nanofluid was applied using ultrasonic irradiation to ensure uniform dispersion and stability. The results demonstrated a substantial improvement in various crude oil properties. The viscosity was reduced significantly, from 58.15 cP to 5.58 cP, representing a 90.4% improvement. The API gravity increased markedly, from 19.63 to 30.49. Furthermore, the heavy metal content decreased considerably, with vanadium reduced from 109.67 ppm to 9.02 ppm (92% reduction) and the nickel content showing an 85% decrease. The sulfur content also declined sharply, from 4.422% to 0.77%, indicating an 83% improvement. These findings confirm the high efficacy of nanofluid-assisted ultrasonic treatment as a promising technique for upgrading heavy crude oil and enhancing its refining and transportation potential.

Long-term containment of CO₂ in geological formations demands cementing systems that can withstand highly aggressive downhole environments, where carbonic acid, brine, and other reactive species threaten the integrity of cement sheath. This review critically examines the deterioration mechanisms of Portland-based cements under CO₂-rich conditions, emphasizing acid-induced decalcification, carbonation, and leaching processes. It further categorizes and compares a broad range of acid-resistant alternatives including modified Portland systems, non-Portland systems (CAC: Calcium Aluminate Cement, CAPC: Calcium Aluminate Phosphate Cement, MPC: Magnesium Phosphate Cement, geo-polymers), resin-based sealants, and nano-engineered formulations, focusing on their chemistry, resistance mechanisms, performance metrics, and field applicability. The review then proposes a detailed laboratory testing system aligned with API standards and introduces a phase-wise testing protocol. A novel conceptual screening criterion (HSR framework) is developed based on operational, design, and sustainability parameters to guide material selection and validation for CO₂-brine exposed cementing systems. Among the systems evaluated, CAC, CAPC, and MPC have shown superior results in terms of post-exposure compressive strength retention and reduced carbonation depth. Key knowledge gaps and challenges are identified, particularly regarding long-term behavior under thermobaric and acidic exposure. Finally, a future roadmap is outlined, calling for systematic field validation, deeper mechanistic insights into CAC and CAPC systems, and innovations in multifunctional, low-carbon binders suited for emerging CCS frontiers.

In oil and gas exploration, kick is a typical high-risk downhole incident. Currently, most intelligent kick detection methods belong to supervised learning, which depends on labeled samples and is prone to class imbalance issues in the training set, leading to reduced model accuracy and higher false alarm rates in practical applications. To address this, this paper focuses on the application of unsupervised learning in kick detection, proposing a kick detection method based on Long Short-Term Memory Autoencoder (LSTM-AE) combined with parameter trend change rules. The study integrates LSTM-AE with expert knowledge to develop an intelligent kick early warning system suitable for well sites, validated using field data from five wells. The results show that the average reconstruction mean squared error of the LSTM-AE is 0.017, with an average false alarm rate of 4.56% for kick detection, detecting kicks an average of 9.2 min earlier than manual detection. This outcome confirms that kick detection can utilize unsupervised learning methods, avoiding relying on labeled samples and class imbalance issues in the training set, thereby effectively improving model accuracy and generalization ability. Moreover, the proposed LSTM-AE demonstrates superior performance in kick detection, and the detection method combining the model and judgment rules has significant implications for monitoring and early warning of other types of downhole incidents.

Gas injection is frequently used to displace the trapped oil. However, this may lead to deposition of asphaltene, which can profoundly block the pores and throats of the porous media, resulting in reduced porosity and permeability. The rock lithology, composition of the injected fluids, pressure, and temperature are among the parameters that may influence asphaltene deposition. This study investigated the asphaltene precipitation/deposition while injecting rich hydrocarbon gas into a heavy oil reservoir. The experiments were conducted under two conditions: miscible and immiscible gas injections. Two rich hydrocarbon gases with different compositions were used, and experiments were conducted under reservoir conditions. Experiments were performed in carbonate cores previously saturated with heavy live oil. The extent of formation damage was assessed by measuring asphaltene deposition during the flooding of miscible and immiscible rich hydrocarbon gases into the core plugs. The outlet oil samples from the core flooding were analyzed using molecular weight measurements, UV spectroscopy, and the IP143 method. During the miscible flooding process, where rich hydrocarbon gas was injected into live oil at 210 ℉, the molecular weight of the outlet oil samples decreased by 53%. The porosity and permeability of the carbonate core in miscible flooding at 210 ℉, after washing with cyclohexane, showed a reduction of 13.6% in porosity and 42.8% in permeability. In the course of immiscible flooding with rich hydrocarbon gas, the outlet oil at 104 ℉ decreased by 48.3% in molecular weight, 35.5% in absorption coefficient, and 30.7% in asphaltene content. The porosity and permeability of the carbonate core in immiscible flooding decreased by 11.8% and 43.25%, respectively. The results showed that both miscible and immiscible injection processes reduce the porosity and permeability of carbonate cores. The damage was particularly severe during the miscible flooding.

The low production of tight gas reservoirs arises from complex and multifaceted causes, and elucidating these factors is crucial for guiding the formulation of effective stimulation strategies. Conventional analytical methods predominantly emphasize the role of individual factors, thereby lacking necessary systematic and integrative perspective to comprehensively reveal underlying mechanisms of poor well performance. To overcome these limitations, a comprehensive diagnostic approach is proposed to identify controlling factors of low production in multilayer tight gas reservoirs. Taking three typical cluster well groups of LX tight gas reservoirs in the Ordos Basin as examples, the causes for the low production of the gas wells were analyzed from different aspects by using geological, engineering, and developmental data after excluding the special reasons such as defects in drilling and completion process, reservoir water lock, and water flooding. The results show that the main causes for the low production of gas wells in LX reservoirs include fewer exploited gas layers, poor physical properties, poor fracturing and fracture making effects, and insufficient formation energy. In addition, corresponding treatment measures such as reperforation and refracturing were proposed. Finally, effects of the measures in the two low-yield wells where the reperforation was implemented were analyzed: the production and Tubing-head pressure increased significantly, and the low-yield wells were transformed into non-low-yield wells with good results. The results of the measures demonstrate the feasibility of the new method.

Underground hydrogen storage (UHS) in saline aquifers is a promising solution for large-scale, long-duration energy storage in a low-carbon energy system. Cushion gases, such as N₂, CO₂, and CH₄, are commonly used to regulate reservoir pressure and enhance storage efficiency. However, despite recent advancements in understanding the interfacial tension (IFT) behavior of H₂-gas mixtures in contact with brine under reservoir conditions, key gaps persist in systematic data for H₂-cushion gas mixtures (e.g., with N₂, CO₂, and CH₄) across specific thermophysical ranges, despite its influence on capillary sealing, gas mobility, and recovery. This study presents systematic experimental measurements of IFT and density for H₂-N₂, H₂-CO₂, and H₂-CH₄ gas mixtures (70:30 mol%) with both distilled water and brine (30,000 ppm NaCl) at different temperatures (25, 50, and 70 ℃) and pressures (1, 5, and 10 MPa). The IFT was measured using a high-pressure, high-temperature drop tensiometer, and density was obtained via an Anton Paar DMA 4500 densitometer. Results show a consistent decrease in IFT with rising temperature and pressure across all systems. Notably, the H₂-CH₄ mixture exhibited an IFT of 69.4 mN/m in distilled water at 25 ℃ and 1 MPa, decreasing to 57.3 mN/m at 70 ℃; in contrast, the same mixture in 30,000 ppm brine showed a larger reduction from 61.3 mN/m to 47.8 mN/m under identical conditions, highlighting the amplifying effect of salinity on IFT decline. Among the gas mixtures, CH₄ yielded the approximately lowest overall IFT values, favoring injectivity, whereas N₂ maintained the highest IFT, supporting enhanced capillary retention. These findings address a critical data gap for realistic cushion gas performance and provide foundational insight for modeling UHS in saline aquifers.

Shale oil reservoirs often experience severe hydraulic fracture stress sensitivity and conductivity damage, leading to rapid production decline and low oil recovery. Understanding fracture damage mechanisms is crucial for optimizing stimulation and production strategies. This study established a novel conductivity damage model of hydraulic fracture incorporating stress sensitivity, gel-breaking residue deposition, and the process of shale particle hydration, expansion, shedding, and blockage. A sensitivity analysis was conducted by numerical simulation to evaluate the impact of different damage mechanisms on fracture conductivity and oil production. The simulation results indicate that different damage mechanisms have varying impacts on fracture conductivity and production. Stress sensitivity significantly reduces main fracture conductivity, but broken gel residue is the primary cause of oil production decline. In branch fractures, both stress sensitivity and broken gel residue decrease conductivity, with stress sensitivity having the greatest impact on production. Shale particle expansion and deposition can further impair fracture conductivity, while particle detachment and output help restore it. Oil production of branch fractures is more sensitive to conductivity damages. These insights can guide fracture design, fracturing fluid optimization, and production control. It is recommended to increase proppant concentration to mitigate the adverse effect of stress sensitivity on oil production, enhance the concentration of anti-swelling agents in the pre-slug of fracturing fluid to better protect branch fractures, and control drawdown pressure to prevent shale particles from detaching and depositing in the fractures.