Abdullah Saad Sultan

Surfactant-assisted CO2 emulsion injection into cold aquifers offers enhanced CO2 storage capacity and accelerated hydrate formation. However, prior studies have largely treated surfactants as either emulsion stabilizers or hydrate kinetic promoters in isolation, leaving unresolved whether the concentration that optimizes CO2 trapping is compatible with that needed for hydrate formation near submarine temperatures. This study addresses that gap through a systematic, multiscale evaluation of SDS-stabilized CO2 emulsions. At ∼3 °C, SDS precipitates before reaching its critical micelle concentration; solubility, interfacial tension, and bulk hydrate formation experiments identify 1000 ppm as a practical upper limit for porous-medium experiments. High-pressure, low-temperature microfluidic experiments show that SDS above 500 ppm improves CO2–water displacement efficiency by increasing effective CO2-phase viscosity and reducing interfacial tension, yielding smaller CO2 ganglia and stable, piston-like displacement. SDS up to 1000 ppm shortens induction times and increases hydrate film growth rates, following a power-law dependence on subcooling with an exponent of 2. CO2 emulsions further sustain open transport pathways via continued CO2 dissolution, enabling efficient long-term CO2-to-hydrate conversion. These results define a concentration window where SDS simultaneously enhances CO2 storage and hydrate kinetics.

Measuring the interfacial tension (IFT) between CO₂ and water is critical for understanding carbon sequestration in depleted oil reservoirs, saline aquifers, and shallow seabeds. In the commonly used pendant drop method, IFT is not measured directly but calculated from the drop's capillary length squared and the user-specified density difference (Δρ). However, in the conventional water-in-gas configuration, CO₂ dissolution continuously increases the aqueous-phase density, making the user-defined Δρ inaccurate and causing significant errors in the calculated IFT. To overcome this, we developed a gas-in-water pendant drop technique where continuous injection creates stable CO₂ bubbles with negligible dissolution in the aqueous phase, enabling precise IFT determination using pure-phase densities. Validated with CH₄-water systems, this method was used to systematically measure CO₂/CH₄-water IFTs from 0-80 °C and up to 50 MPa. Results show IFT stabilizes at low temperatures with increasing pressure, and an empirical correlation based on density difference and temperature effectively captures the behavior, providing a critical foundation for CO₂ storage and gas hydrate studies.

Matrix acidizing is a widely employed stimulation technique that enhances well productivity in carbonate reservoirs by dissolving formation damage and creating conductive channels known as wormholes. Conventional hydrochloric acid (HCl) systems, while effective, suffer from limitations such as high corrosivity, excessive reactivity, and poor thermal stability. Emulsified acid systems (EAS) have emerged to address these drawbacks by introducing an oil phase that slows the acid-rock reaction and facilitates deeper penetration. However, the high viscosity of surfactant-based EAS leads to increased pumping resistance and energy consumption. This study introduces a Pickering emulsified acid system (PEAS) formulated using organoclay (OC) nanoparticles as solid-particle emulsifiers to overcome these limitations. PEAS exhibits enhanced thermal stability, compatibility, and drag-reducing characteristics due to the rheological behavior and lubricity of OC. Comparative flow-loop tests with 15% and 20% HCl revealed significantly lower frictional pressure drops for PEAS than traditional EAS across a range of temperatures (25-50 °C). Postflow characterization including conductivity, stability, and rheology analyses confirmed the structural robustness and field-relevant performance of PEAS. These findings position PEAS as a promising, environmentally friendly fluid system for improving acid placement, enabling efficient wormhole formation and reducing the energy footprint of matrix acidizing operations.

Summary: The oil and gas industry faces numerous challenges, among which the management of excessive water production is a significant concern. Nanosilica gel is a newly developed silicate gel for water shutoff applications. No investigation has been conducted to evaluate the gel’s performance over an extended period. The objective of this study is to evaluate the long-term performance of nanosilica gel in a permeable matrix over 6 months while also comparing this performance with polyacrylamide/polyethyleneimine (PAM/PEI) gel. Coreflooding experiments were conducted to evaluate the performance of the nanosilica gel of 75/25 wt% (nanosilica/activator) and PAM/PEI gel (9/1 wt%) on carbonate core samples at 200°F. The experiment involved initial permeability assessment, gel placement, and endurance tests up to 1,000 psi. Additional measurements of computed tomography (CT) scan and nuclear magnetic resonance (NMR) were implemented: CT scans visualized density changes, and NMR measured fluid distribution in the pore system. Then, samples were aged at 167°F for 6 months, with endurance tests (up to 1,000 psi) conducted in the first, third, and sixth months to assess gel-plugging efficiency. The results demonstrated nanosilica gel’s remarkable plugging efficiency, achieving a reduction in permeability from 144.85 md to 0.001 md initially and sustaining differential pressures up to 1,000 psi with minimal leakoff rates. After 6 months, nanosilica gel maintained plugging efficiency above 99.98%, while PAM/PEI gel efficiency reduced to 99.85%. The nanosilica gel achieved slightly better long-term plugging performance than PAM/PEI gel with a maximum leakoff rate of 0.25 cm3/min in 6 months (2.165 cm3/min for PAM/PEI gel). CT scan analysis confirmed effective gel placement within the pore systems, and minimal degradation occurred over time with less significant impact on the efficiency of nanosilica gel compared with PAM/PEI gel.

In the context of mature oil fields, the management of conformance control and water shut-off stands out as a formidable challenge. Our prior research endeavors (Saikia et al., 2021, 2020) have introduced an innovative Pickering emulsified gel system tailored for the precise adjustment of relative permeability in high-temperature reservoirs. To optimize the efficiency of this system, a comprehensive comprehension of the underlying conformance control mechanism is deemed imperative. Traditionally, the exploration of conformance control mechanisms leans on empirical data culled from core flooding experiments, computerized tomography (CT) scans, nuclear magnetic resonance spectroscopy (NMR), and analogous methodologies. Nevertheless, these conventional avenues often fall short in delivering real-time visual analyses, thereby raising doubts about their reliability in predicting conformance mechanisms. In our research study, we have harnessed the capabilities of microfluidics to unlock real-time visual insights into the mechanisms governing conformance control. Employing two distinct glass micromodel geometries, we have conducted Pickering emulsified gel treatments at a scorching 105°C to achieve the targeted conformance control within these micromodels. By synergizing image and video analysis with injection pressure measurements, our findings have cast doubt on the previously posited Thin Film conformance control mechanism, revealing a more nuanced perspective on this intricate process.

Matrix acidizing is a technique that is widely used in the petroleum industry to remove scales and create channels in the rock. Removal of scales and creation of channels (wormhole) enhance productivity. Conventional acidizing fluids, such as hydrochloric acid (HCl) for carbonate and a mixture of hydrofluoric acid (HF) and HCl acid, are used for the matrix acidizing process. However, these fluids have some drawbacks, including strong acid strength, corrosion at high temperatures, and quick reactions with scale and particles. Emulsified acid systems (EASs) are used to address these drawbacks. EASs can create deeper and narrower wormholes by reducing the reaction rate of the acid due to the external oil phase. However, EASs have a much higher viscosity compared to conventional acidizing fluids. The high viscosity of EASs leads to a high drag that restricts pumping rates and consumes energy. This study aims to utilize environmentally friendly and widely available nanomaterials as drag-reducing agents (DRAs) of the EAS. The nanomaterials used in this study are carbon nanodots (CNDs). CNDs have unique properties and are used in diverse applications in different industries. The size of these CNDs is usually smaller than 10 nm. CNDs are characterized by their biocompatibility and chemical stability. This study investigates the use of CNDs as DRAs for EAS. Several experiments have been conducted to investigate the CNDs as a DRA for the EAS. The developed EAS was initially tested for conductivity and drop-test analysis to ensure the formation of an inverted emulsion. Thereafter, the thermal stability for the range of temperatures and the rheological properties of the EAS were evaluated to meet the criteria of field operation. Then flow experiments with EASs were conducted before and after adding the CNDs to investigate the efficacy of drag reduction of EASs. The results revealed that CNDs can be used as viscosity reducers for the EAS, where adding the CNDs to the EAS reduces the viscosity at two different HCl concentrations (15 and 20%). It reduces the viscosity of the EAS in the presence of corrosion inhibitors as well as other additives to the EAS, showing its compatibility with the field formulation. The drag reduction was observed at the range of temperatures investigated in the study. The conductivity, stability, and rheology experiments for the sample taken after the flow experiment are consistent, ensuring CNDs work as a DRA. The developed EAS with CNDs is robust in terms of field mixing procedures and thermally stable. The CNDs can be used as a DRA with EAS, which will reduce drag in pipes, increasing pumping rates and saving energy.

Summary: One of the most extensively studied flow assurance issues in the petroleum industry is the precipitation and deposition of asphaltenes. This is in part because of the molecular structure’s intricacy and the interconnected factors that influence and regulate its activity. The injection of inhibitors and dispersants, which affects the economics of crude oil production, is now the most successful strategy for preventing asphaltene problems. Throughout the crude oil supply chain, from the reservoir through the tubing and refinery systems, asphaltene is a concern. However, the area closest to the wellbore, where the highest pressure drop is seen, is the most prone to asphaltene adsorption and deposition. Thus, the goal of this study is to investigate the use of sacrificial fluids to reduce asphaltene adsorption and deposition around the wellbore. To prevent asphaltene from interacting with the rock surface and shifting the asphaltene problem into tubing, where its impact on wettability is low, polymers with functional capabilities are investigated. The performance test (adsorption inhibition capacity), binding energy analysis, adsorption experiments (adsorption affinity, configuration, and mechanism), and fluid characterization (salinity tolerance, surface energy, and interfacial tension) of the selected novel fluids for asphaltene adsorption mitigation are presented. The investigation of ion-specific rock-fluid interactions offers great potential in the search for an effective answer to the asphaltene problem, according to the results. This was proved by the fluid levels of binding energy to carbonate rock samples and their capacity to prevent interactions between asphaltene molecules and the rock surface. These findings provide a fresh perspective on the creation of an economic strategy to deal with asphaltene issues and their effects. This study is the first to investigate a long-term fix for wettability changes caused by asphaltene adsorption on rock minerals. The findings revealed that an optimal concentration exists for the polymers under study, at which the asphaltene interaction is mitigated. More so, surface energy evaluation is observed to be a critical tool that can help to screen polymers for this application. Furthermore, the method of implementation, which could be either squeeze operation or continuous injection, is critical to the success of the remediation.