Understanding the failure mechanisms of resin‐coated proppants under extreme environments facilitates the development of stronger proppants for superior long‐term performance in the oil and gas sector. In the current study, the leaching behavior of Novolac resin‐coated proppants (RCPs) and that of polyurethane (PU) based RCPs with aqueous media under different pH conditions and at elevated temperatures have been critically examined, to assess their chemical stability and integrity. Our study indicates that Novolac‐based RCPs are substantially more stable to leaching conditions at 250 °F compared to PU‐based RCPs. An in‐depth nuclear magnetic resonance analysis of the aqueous leachates from the RCP systems reveals that the averaged total levels of the leached components from the PU‐based RCPs is five‐ to sevenfold higher than those of the Novolac RCPs at the higher temperature. In addition, a critical examination of the Novolac RCPs from a product safety and environmental health viewpoint is accomplished by ultraviolet–visible spectrophotometric analysis of the aqueous leachates. The findings reveal that the concentrations of the phenolics, including free phenol, are lower than the detectable limits (<1 ppm) of the technique. © 2017 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018, 135, 45845.

Hydraulic fracturing is a well-known stimulation technique for creating fractures in a subsurface formation to achieve profitable production rates in low-permeability reservoirs. Slickwater has been widely used as a traditional fracturing fluid. However, it has multiple disadvantages, such as high consumption of water, clay swelling and low flowback recovery. Foam, as an alternative fracturing fluid, consumes less liquid and provides additional energy. However, foam bubbles are typically unstable due to the degradation of surfactants, particularly in high temperature reservoirs, which reduces their capabilities of carrying and placing proppants into fractures. The purpose of this study is to provide general guidelines for an optimised application of polymers to improve the foam stability in high temperature reservoirs while increasing the proppant placement and water usage efficiencies. In this paper, the effects of natural hydroxypropyl guar (HPG) and synthetic polyacrylamide (PAM) polymers on the rheological properties of nitrogen foam-based fluids were examined by laboratory experiments conducted using temperatures up to 110°C. Then, a 3D hydraulic fracture propagation model was developed to study the fracturing performance of HPG-foamed and PAM-foamed fluids in the Toolachee Formation, Cooper Basin. It was found that synthetic PAM polymers were more effective than natural HPG polymers in stabilising foam viscosity under high temperature conditions. The simulation results indicate that foam-based fluids totally outperform slickwater in the field case application. This paper emphasises the significance of crosslinkers, foam quality and thermal stability on the performance of foams in high temperature environments.

Hydraulic fracture stimulation is one of the most effective methods to recover oil and gas from unconventional resources. In recent years, foam-based fracturing fluids have been increasingly studied to address the limitations of conventional slickwater such as high water and chemical consumption, environmental concerns, and high incompatibility with water-sensitive formations. Due to the gradual breakdown of liquid foams at reservoir conditions, the combination of silica nanoparticles (SNP) and surfactants has attracted a lot of attention to improve liquid foams’ characteristics, including their stability, rheology, and proppant-carrying capacity. This paper investigates and compares the effects of cationic and anionic surfactants on the fracturing performance of SNP-stabilized foams at the reservoir temperature of 90 °C. The experimental results of viscosity measurements were imported into a 3D fracture-propagation model to evaluate the effectiveness of fracturing foams in transporting and distributing proppants in the fracture system. At both ambient and elevated temperatures, cationic surfactant was experimentally found to have better synergistic effects with SNP than anionic surfactant in improving the apparent viscosity and proppant-carrying capacity of foams. The simulation results demonstrate that fracturing with cationic surfactant-SNP foam delivers greater performance with larger propped area by 4%, higher fracture conductivity by 9%, and higher cumulative gas production by 13%, compared to the anionic surfactant-SNP foam. This research work not only helps validate the interrelationship between fluid viscosity, proppant settlement rate, and fracture effectiveness, but it also emphasizes the importance of proppant placement in enhancing fracture conductivity and well productivity.

Foam-based fracturing fluids have emerged as a viable alternative to conventional water-based systems for hydraulic fracturing in high-pressure, high-temperature (HPHT) reservoirs, where fluid efficiency, formation protection, and environmental considerations are critical. The performance of these fluids is governed by a strong coupling between foam stability, rheological behavior, and proppant transport capacity under elevated temperature and pressure conditions. This chapter presents a comprehensive analysis of foam-based fracturing fluids for HPHT applications, integrating experimental observations and modeling insights to link laboratory-scale characterization with fracture-scale performance. Key aspects examined include foam quality, surfactant chemistry, nanoparticle stabilization, salinity effects, and their combined influence on apparent viscosity, shear-thinning behavior, viscoelastic response, and drainage characteristics. Results from high-temperature rheometry, stability testing, and proppant transport studies demonstrate that enhanced foam stability leads to improved rheological resilience and more effective proppant suspension under HPHT conditions. Simulation studies further illustrate how these rheological properties translate into fracture propagation and proppant placement outcomes. The findings provide practical guidance for the design and selection of foam-based fracturing fluids in deep and thermally challenging reservoirs, supporting safer, more efficient, and lower water-intensity stimulation strategies.