Advanced Polymer Composites in Oil Industry

Addressing the issue of inadequate temperature tolerance in traditional polymers, in this study, we successfully executed a one-step synthesis of intelligent–responsive polymers which have excellent adaptability in water–gas alternating displacement scenarios. Utilizing the fatty acid method, we produced OANND from oleic acid (OA) and N,N-dimethyl-1,3-propanediamine (NND). Upon testing the average particle size in the aqueous solution both prior and subsequent to CO₂ passage, it became evident that OANND assumes the form of a small-molecule particle in the aqueous phase, minimizing damage during formation. Notably, upon CO₂ exposure, it promptly organizes into stable micelles with an average size of 88 nm and a relatively uniform particle distribution. This unique characteristic endows it with a rapid CO₂ response mechanism and the ability to form a highly resilient gel. In the exploration of viscoelastic fluids, we observed the remarkable behavior of the AONND aqueous solution when CO₂/N₂ was introduced. This system displayed repeatable transitions between aqueous and gel states, with the highest viscosity peaking at approximately 3895 mPa·s, highlighting its viscosity reversibility and reusability properties. The rheological property results that we obtained indicate that an elongated micellar structure is present in the solution system, with the optimal concentration ratio for its formation determined as 0.8, which is the molar ratio of the OANND-NaOA system. In the sealing performance tests, a 1.0 wt% concentration of the gel system exhibited excellent injectability properties. At 80 °C, this gel effectively reduced the permeability of a sand-filled model to 94.5% of its initial value, effectively sealing potential leakage paths or gas fluxes. This remarkable ability to block leakage paths and reduce seepage capacity highlights the material’s superior blocking effect and erosion resistance properties. Furthermore, even at a temperature of 90 °C and an injection pore volume (PV) of 3, this plugging system could reduce the permeability of a high-permeability sand-filled model to over 90% of its initial value. Full article

Aliphatic polyester is an important polyester material with good biocompatibility and degradability, which can be synthesized through ring-opening alternating copolymerization (ROAC) of epoxides and anhydrides. Herein, density functional theory (DFT) is used to explore the mechanism of ROAC of epoxides (propylene oxide (PO), styrene oxide (SO), epichlorohydrin (ECH), and cyclohexane oxide (CHO)) and phthalic anhydride (PA) catalyzed by bis(triphenylphosphine) ammonium chloride (PPNCl) and ureas. It was found that the ring-opening polymerization (ROP) of epoxides is the rate-controlling step, and the benzyl alcohol (BnOH) as the initiator has little effect on the polymerization activity, which was consistent with previous experimental results. Calculated comparisons of the ROAC activity of CHO/PA catalyzed by four different ureas indicate that as the Lewis acidity of the urea increased, the energy barriers of the copolymerization increased and the activity decreased. The main reason was that the strong hydrogen-bonding interactions stabilized the key intermediate of the rate-controlling step and inhibited subsequent monomer insertion. Based on this, a series of new ureas with higher catalytic activity were designed by introducing electron-donating substituents. In SO polymerization, increasing the Lewis acidity of urea can improve the SO regioselectivity. In addition, the monomer ECH with CH₂Cl shows higher activity of ROAC than PO and SO, which could be ascribed to the fact that the strong electron-withdrawing Cl atom stabilizes the transition state in the rate-controlling step and reduces the reaction energy barrier. Full article

Preformed particle gels (PPGs) based on acrylamide (AAm), (3-acrylamidopropyl) trimethylammonium chloride (APTAC), and 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS) were synthesized via conventional free radical copolymerization. The resultant PPGs of various compositions were characterized using FTIR spectroscopy, TG and DT analysis, and mechanical testing. The swelling behavior of PPGs depending on ionic strength, temperature, degree of crosslinking, and pH was also studied. The obtained results show that the swelling mechanism of PPGs is mainly due to the diffusion of the solvent. The mechanical properties of PPGs were improved by creating a composite polymer network by adding the clay mineral (bentonite) to the reaction mixture of monomers, which also makes it possible to control the Young’s modulus and the swelling degree of the samples. Full article

Oil recoveries from medium and heavy oil reservoirs under natural recovery production are small because of the high viscosity of the oil. Normal water flooding procedures are usually ineffective, as the injected water bypasses much of the oil because of its high mobility. Thermal flooding processes are desirable but have many disadvantages from costs, effects on the environment, and loss of lighter hydrocarbons. Chemical flooding options, such as bio-polymer flooding options, are attractive, as they are environmentally friendly and relatively cheap to deploy and help to increase the viscosity of the injecting fluid, thereby reducing its mobility and increasing its oil recovery. The downside to polymer flooding includes reservoir temperature, salinity, molecular weight, and composition. Six weight percentages of two polymers (xanthan gum, XG, and gum arabic, GA) are dissolved in water, and their viscosity is measured in the laboratory. These viscosities are incorporated with correlations in the Eclipse software to create models with different polymer concentrations of (0.1% wt., 0.2% wt., 0.3% wt., 0.4% wt., 0.5% wt., and 1% wt.). A base case of natural recovery and water injection was simulated to produce an oil recovery of 5.9% and 30.8%, respectively, while at 0.1% wt. and 1% wt., respectively, oil recoveries of 38.8% and 45.7% (for GA) and 48.1% and 49.8% (for XG) are estimated. At 5% and 10% saline conditions, a drop in oil recovery of (4.6% and 5.3%) is estimated during GA flooding and (1.2% and 1.7%) for XG flooding at 1% wt., respectively. XG exhibits higher oil recoveries compared to GA at the same % wt., while oil recoveries during GA floodings are more negatively affected by higher saline concentrations. Full article

After polymer flooding in Daqing Oilfield, the heterogeneity of the reservoir is enhanced, leading to the development of the dominant percolation channels, a significant issue with inefficient circulation, a substantial amount of displacement agents, and elevated cost. In order to further improve oil recovery, an adaptive oil displacement system (ASP-PPG) was proposed by combining preformed particle gel (PPG) with an alkali-surfactant-polymer system (ASP). This comprehensive study aims to assess the effectiveness of the adaptive oil displacement system (ASP-PPG) in improving the recovery efficiency of heterogeneous reservoirs after polymer flooding. The evaluation encompasses various critical aspects, including static performance tests, flow experiments, microscopic experiments, profile control experiments, and flooding experiments conducted on a four-layer heterogeneous physical model. The experimental results show that the adaptive system has robust stability, enhanced mobility, effective plugging capability, and profile improvement capability. Notably, the system demonstrates the remarkable ability to successfully pass through the core and effectively block the large pores, resulting in an 18.4% recovery incremental after polymer flooding. This improvement is reflected in the reduced oil saturation values in the ultra-high permeability, high permeability, medium, and low permeability layers, which are 5.09%, 7.01%, 13.81%, and 15.45%, respectively. The adaptive system effectively recovered the remaining oil in the low and medium permeability layers, providing a promising approach for improving the recovery factors under challenging reservoir conditions. Full article

The purpose of this study is to clarify the difference in oil production rules of conglomerate reservoirs with different pore structures during surfactant–polymer (SP) binary flooding and to ensure the efficient development of conglomerate reservoirs. In this paper, the full-diameter natural cores from the conglomerate reservoir of the Triassic Kexia Formation in the seventh middle block of the Karamay Oilfield (Xinjiang, China) are selected as the research objects. Two schemes of single constant viscosity (SCV) and echelon viscosity reducing (EVR) are designed to displace oil from three main oil-bearing lithologies, namely fine conglomerate, glutenite, and sandstone. Through comprehensive analysis of parameters, such as oil recovery rate, water content, and injection pressure difference, the influence of lithology on the enhanced oil recovery (EOR) of the EVR scheme is determined, which in turn reveals the differences in the step-wise oil production rules of the three lithologies. The experimental results show that for the three lithological reservoirs, the oil displacement effect of the EVR scheme is better than that of the SCV scheme, and the differences in recovery rates between the two schemes are 9.91% for the fine conglomerate, 6.77% for glutenite, and 6.69% for sandstone. By reducing the molecular weight and viscosity of the SP binary system, the SCV scheme achieves the reconstruction of the pressure field and the redistribution of seepage paths of chemical micelles with different sizes, thus, achieving the step-wise production of crude oil in different scale pore throats and enhancing the overall recovery of the reservoir. The sedimentary environment and diagenesis of the three types of lithologies differ greatly, resulting in diverse microscopic pore structures and differential seepage paths and displace rules of SP binary solutions, ultimately leading to large differences in the enhanced oil recoveries of different lithologies. The fine conglomerate reservoir has the strongest anisotropy, the worst pore throat connectivity, and the lowest water flooding recovery rate. Since the fine conglomerate reservoir has the strongest anisotropy, the worst pore throats connectivity, and the lowest water flooding recovery, the EVR scheme shows a good “water control and oil enhancement” development feature and the best step-wise oil production effect. The oil recovery rate of the two schemes for fine conglomerate shows a difference of 10.14%, followed by 6.36% for glutenite and 5.10% for sandstone. In addition, the EOR of fine conglomerate maintains a high upward trend throughout the chemical flooding, indicating that the swept volume of small pore throats gradually expands and the producing degree of the remaining oil in it gradually increases. Therefore, the fine conglomerate is the most suitable lithology for the SCV scheme among the three lithologies of the conglomerate reservoirs. Full article