Experimental investigation of wettability alteration, IFT reduction, and injection schemes during surfactant/smart water flooding for EOR application

Mechanistic understanding of asphaltene precipitation and oil recovery enhancement using SiO2 and CaCO3 nano-inhibitors

Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid-base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors.

New molecular and macroscopic understandings of novel green chemicals based on Xanthan Gum and bio-surfactants for enhanced oil recovery

This research investigates the interactions between a novel environmentally friendly chemical fluid consisting of Xanthan gum and bio-based surfactants, and crude oil. The surfactants, derived from various leaves using the spray drying technique, were characterized using Fourier-transform infrared (FTIR) spectroscopy, zeta potential analysis, Dynamic light scattering, and evaluation of critical micelle concentration. Static emulsion tests were conducted to explore the emulsification between crude oil and the polymer-surfactant solution. Analysis of the bulk oil FTIR spectra revealed that saturated hydrocarbons and light aromatic hydrocarbons exhibited a higher tendency to adsorb onto the emulsion phase. Furthermore, the increased presence of polar hydrocarbons in emulsion phases generated by polar surfactants confirmed the activation of electrostatic forces in fluid-fluid interactions. Nuclear magnetic resonance spectroscopy showed that the xanthan solution without surfactants had a greater potential to adsorb asphaltenes with highly fused aromatic rings, while the presence of bio-based surfactants reduced the solution's ability to adsorb asphaltenes with larger cores. Microfluidic tests demonstrated that incorporating surfactants derived from Morus nigra and Aloevera leaves into the xanthan solution enhanced oil recovery. While injection of the xanthan solution resulted in a 49.8% recovery rate, the addition of Morus nigra and Aloevera leaf-derived surfactants to the xanthan solution increased oil recovery to 58.1% and 55.8%, respectively.

Experimental investigation of the sequence injection effect of sea water and smart water into an offshore carbonate reservoir for enhanced oil recovery

This study explores enhanced oil recovery (EOR) strategies, with a focus on carbonate reservoirs constituting over 60% of global oil discoveries. While "smart water" injection proves effective in EOR for carbonate reservoirs, offshore application challenges arise due to impractical volumes for injection. To address this, we propose a novel continuous injection approach, systematically investigating it on a laboratory scale using the Iranian offshore reservoir, Sivand. Thirty-six contact angle tests and twelve flooding experiments are meticulously conducted, with key ions, potassium, and sulfate, playing pivotal roles. Optimal wettability alteration is observed at 4 times potassium ion concentration in 0-2 times sulfate concentrations, driven by ionic strength and charge interactions. Conversely, at 3-5 times sulfate concentrations, the optimal contact angle shifts to 2 times potassium ion concentration, suggesting a mechanism change linked to increasing sulfate ion ionicity. A significant wettability alteration, evidenced by a 132.8° decrease, occurs in seawater with a twofold concentration of potassium ions and a fivefold concentration of sulfate ions. Micromodel experiments introduce an innovative alternation of smart water and seawater injections. The first scenario, smart water followed by seawater injection, reveals negligible post-seawater injection oil recovery changes. In contrast, the second scenario yields a maximum recovery of 7.9%. The first scenario, however, boasts superior overall sweep efficacy, reaching approximately 43%. This research expands understanding of smart water and seawater injection in EOR, presenting a viable solution for optimizing offshore carbonate reservoir recovery. The insights contribute to evolving EOR methodologies, emphasizing tailored strategies for varying reservoir conditions.

Underground geological sequestration of carbon dioxide (CO2) and its effect on possible enhanced gas and oil recovery in a fractured reservoir of Eastern Potwar Basin, Pakistan

Due to concerns over rising emissions of carbon dioxide (CO2) from fossil fuel utilization, there has been a strong emphasis on the development of a safe, economical, practical method of carbon capture utilization and storage (CCUS). One way to reduce these CO2 emissions is underground geological sequestration in depleted oil fields or exhausted reservoirs. CO2 injection into oil reservoirs is an established technology, these reservoirs not only offer the potential for high storage of CO2 but this process could also target a large amount of oil and gas recovery through a technique called enhanced oil recovery (EOR). The main objective of this research was to evaluate the storage potential of CO2 in the depleted oil field while also investigating the effect of CO2 injection on reservoir pressure maintenance, and additional oil and gas recovery, in the same field. This paper presented the model of CO2 flooding based on the CO2 displacement mechanism with different scenarios of natural depletion, CO2 injection, and water injection simulated by the ECLIPSE 300 reservoir simulator, and the results of different scenarios were compared. Results of this study showed the site selected for CO2 injection has the potential to store more than 9 billion cubic feet (BCF) of CO2 in each case and witnessed improved gas recovery, while also having a major effect on reservoir pressure maintenance where pressure increased from 2120 psi to 6584 psi. The finding of this work ought to help in preparing for future improvement in underground geological sequestration of CO2 in depleted fields with the same field specifications.