Microstructure, dispersion, and flooding characteristics of intercalated polymer for enhanced oil recovery

A review on the effectiveness of nanocomposites for the treatment and recovery of oil spill

The introduction of unintended oil spills into the marine ecosystem has a significant impact on aquatic life and raises important environmental concerns. The present review summarizes the recent studies where nanocomposites are applied to treat oil spills. The review deals with the techniques used to fabricate nanocomposites and identify the characteristics of nanocomposites beneficial for efficient recovery and treatment of oil spills. It classifies the nanocomposites into four categories, namely bio-based materials, polymeric materials, inorganic-inorganic nanocomposites, and carbon-based nanocomposites, and provides an insight into understanding the interactions of these nanocomposites with different types of oils. Among nanocomposites, bio-based nanocomposites are the most cost-effective and environmentally friendly. The grafting or modification of magnetic nanoparticles with polymers or other organic materials is preferred to avoid oxidation in wet conditions. The method of synthesizing magnetic nanocomposites and functionalization polymer is essential as it influences saturation magnetization. Notably, the inorganic polymer-based nanocomposite is very less developed and studied for oil spill treatment. Also, the review covers some practical considerations for treating oil spills with nanocomposites. Finally, some aspects of future developments are discussed. The terms "Environmentally friendly," "cost-effective," and "low cost" are often used, but most of the studies lack a critical analysis of the cost and environmental damage caused by chemical alteration techniques. However, the oil and gas industry will considerably benefit from the stimulation of ideas and scientific discoveries in this field.

Optimization of High Temperature-Resistant Modified Starch Polyamine Anti-Collapse Water-Based Drilling Fluid System for Deep Shale Reservoir

During drilling in deep shale gas reservoirs, drilling fluid losses, hole wall collapses, and additional problems occur frequently due to the development of natural fractures in the shale formation, resulting in a high number of engineering accidents such as drilling fluid leaks, sticking, mud packings, and buried drilling tools. Moreover, the horizontal section of horizontal well is long (about 1500 m), and the problems of friction, rock carrying, and reservoir pollution are extremely prominent. The performance of drilling fluids directly affects drilling efficiency, the rate of engineering accidents, and the reservoir protection effect. In order to overcome the problems of high filtration in deep shale formations, collapse of borehole walls, sticking of pipes, mud inclusions, etc., optimization studies of water-based drilling fluid systems have been conducted with the primary purpose of controlling the rheology and water loss of drilling fluid. The experimental evaluation of the adsorption characteristics of "KCl + polyamine" anti-collapse inhibitor on the surface of clay particles and its influence on the morphology of bentonite was carried out, and the mechanism of inhibiting clay mineral hydration expansion was discussed. The idea of controlling the rheology and water loss of drilling fluid with high temperature resistant modified starch and strengthening the inhibition performance of drilling fluid with "KCl + polyamine" was put forward, and a high temperature-resistant modified starch polyamine anti-sloughing drilling fluid system with stable performance and strong plugging and strong inhibition was optimized. The temperature resistance of the optimized water-based drilling fluid system can reach 180 °C. Applied to on-site drilling of deep shale gas horizontal wells, it effectively reduces the rate of complex accidents such as sticking, mud bagging, and reaming that occur when resistance is encountered during shale formation drilling. The time for a single well to trip when encountering resistance decreases from 2-3 d in the early stages to 3-10 h. The re-use rate of the second spudded slurry is 100 percent, significantly reducing the rate of complex drilling accidents and saving drilling costs. It firmly supports the optimal and rapid construction of deep shale gas horizontal wells.

Gel-Forming and Plugging Performance Evaluation of Emulsion Polymer Crosslinking System in Fractured Carbonate Rock

The water channeling of fractured carbonate rock seriously affects oil recovery, and this problem is especially serious in the Kazakh North Troyes oilfield. A conventional powder polymer plugging system needs to be hydrated ahead of time, which increases the cost and difficulty of field operation and it cannot realize large-scale plugging operations. The new emulsion polymer crosslinked system can realize rapid hydration and real-time mixing, having low base liquid viscosity and good fluidity and injectability. The results of the laboratory study show that the gelling time of HR9806 emulsion polymer and organic chromium crosslinker was 6~8 h. 0.5 wt % HR9806, which is recommended for field use with P/C ranging from 2.5 to 5.0. The emulsion polymer crosslinking system was found to be highly adaptable in reservoirs and had salinity resistance. Mineral salt and reservoir core were able to enhance the gel strength of the system but shortened the gelling time of the system by about 2 h. The gel (HR9806) had good shear resistance. It still had a viscosity of 220 mPa·s under high-speed shearing (Temperature = 54 °C), and the formed gel system shear resistance increased with increasing concentration. The emulsion system of “0.50 wt % HR9806 emulsion polymer + 0.15 wt % organic chromium crosslinker + brine” had a strong plugging effect in the fractured core and sand-filled pipe model, with residual resistance coefficient ≥30, effective plugging rate ≥ 95.0%, and oil–water selectivity of 0.45. In this paper, the levels of weak gel strength were used, providing an experimental and theoretical reference for improving the application effect of the weak gel system in the field. The study found that the weak gel system can better enter the fractured carbonate reservoir and form a plugging effect in the fracture, improving the effect of subsequent water flooding matrix oil recovery.

Di- and Mono-Rhamnolipids Produced by the Pseudomonas putida PP021 Isolate Significantly Enhance the Degree of Recovery of Heavy Oil from the Romashkino Oil Field (Tatarstan, Russia)

Around the globe, only 30–50% of the amount of oil estimated to be in reservoirs (“original oil in place”) can be obtained using primary and secondary oil recovery methods. Enhanced oil recovery methods are required in the oil processing industry, and the use of microbially produced amphiphilic molecules (biosurfactants) is considered a promising efficient and environmentally friendly method. In the present study, biosurfactants produced by the Pseudomonas putida PP021 isolate were extracted and characterized, and their potential to enhance oil recovery was demonstrated. It was found that the cell-free biosurfactant-containing supernatant decreased the air–water interface tension from 74 to 28 mN m−1. Using TLC and FTIR methods, the biosurfactants produced by the isolate were classified as mono- and di-rhamnolipid mixtures. In the isolates’ genome, the genes rhlB and rhlC, encoding enzymes involved in the synthesis of mono- and di-rhamnolipids, respectively, were revealed. Both genes were expressed when the strain was cultivated on glycerol nitrate medium. As follows from the sand-packed column and core flooding simulations, biosurfactants produced by P. putida PP021 significantly enhance the degree of recovery, resulting in additional 27% and 21%, respectively.