Chemical and Physical Architecture of Macromolecular Gels for Fracturing Fluid Applications in the Oil and Gas Industry; Current Status, Challenges, and Prospects

Hydraulic fracturing is vital in recovering hydrocarbons from oil and gas reservoirs. It involves injecting a fluid under high pressure into reservoir rock. A significant part of fracturing fluids is the addition of polymers that become gels or gel-like under reservoir conditions. Polymers are employed as viscosifiers and friction reducers to provide proppants in fracturing fluids as a transport medium. There are numerous systems for fracturing fluids based on macromolecules. The employment of natural and man-made linear polymers, and also, to a lesser extent, synthetic hyperbranched polymers, as additives in fracturing fluids in the past one to two decades has shown great promise in enhancing the stability of fracturing fluids under various challenging reservoir conditions. Modern innovations demonstrate the importance of developing chemical structures and properties to improve performance. Key challenges include maintaining viscosity under reservoir conditions and achieving suitable shear-thinning behavior. The physical architecture of macromolecules and novel crosslinking processes are essential in addressing these issues. The effect of macromolecule interactions on reservoir conditions is very critical in regard to efficient fluid qualities and successful fracturing operations. In future, there is the potential for ongoing studies to produce specialized macromolecular solutions for increased efficiency and sustainability in oil and gas applications.

Synthesis, Characterization, and Properties of a Novel Hyperbranched Polymers with Polyacrylamide Side Chains

A novel hyperbranched polymer with polyacrylamide side chains (HAPAM) was synthesized by aqueous solution polymerization using acrylic acid, acrylamide, 2-acrylamido-2-methyl-1-propanesulfonic acid, hydrophobic monomer of dimethyl octadecyl ammonium chloride, and the homemade skeleton monomer of modified-M2.0 as raw materials and (NH4)2S2O8-NaHSO3 as initiator. The molecular structure, functional groups, and surface morphology of HAPAM were characterized by Fourier transform infrared spectroscopy, nuclear magnetic resonance hydrogen spectroscopy, and scanning electron microscopy. It was found that the performance of HAPAM solution was higher than that of ordinary polyacrylamide solution in terms of thickening ability, shearing resistance, thermal endurance, salt-resistance, resistance-coefficient and residual-resistance-coefficient, ability to reduce interfacial tension between polymer solution and crude oil, and oil-displacement-efficiency. In particular, the enhanced oil recovery of the HAPAM solution was 13.03%, and the improvement of shearing resistance and immunity to chromatographic separation were simultaneously achieved by the HAPAM solution. These results indicate that the successful synthesis of the novel HAPAM opens a promising strategy for developing new high-performance oil-displacing polymers.

Alkali Effect on Alkali-Surfactant-Polymer (ASP) Flooding Enhanced Oil Recovery Performance: Two Large-Scale Field Tests’ Evidence

Alkali-surfactant-polymer (ASP) flooding is very promising chemical enhanced oil recovery (EOR) technology which can make an incremental oil recovery factor (IORF) of 30% original oil in place (OOIP). How to choose alkali in ASP flooding remains a question for a long time. As the world’s only and largest ASP flooding application place, Daqing Oilfield has always adhered to the strategy of parallel development of strong alkali ASP flooding (SASP) and weak alkali ASP flooding (WASP), but SASP is in a dominant position, indicated by more investments and more project numbers. This leaves an impression that SASP is better than WASP. However, WASP is drawing more interest than SASP recently. Moreover, as the ASP flooding in Daqing went from field tests to commercial applications since 2014, how to comprehensively consider the benefit and cost of ASP flooding has become a new focus at low oil prices. This paper compares two typical large-scale field tests (B-1-D SASP and B-2-X WASP) completed in Daqing Oilfield and analyzes and discusses the causes of this difference. The injection viscosity and interfacial tension (IFT) for the two field test areas are substantially equivalent under the conditions of Daqing Oilfield, and WASP is better than SASP when reservoir geological conditions are considered. WASP exhibits the same IORF of 30% as SASP while having a much better economic performance. For the SASP field test, the injected strong alkali NaOH makes the test behave unlike a typical strong ASP flooding due to the presence of CO2 in the formation fluid, which well explains why IORF is much higher than all the other SASPs but scaling is less severe than others. This paper confirms that under Daqing Oilfield reservoir conditions, it is the alkali difference that caused the performance difference of these two tests, although some minor uncertainties exist. WASP is better than the SASP providing the same conditions . In addition, the detailed information of the two ASP field tests provided can give reference for the implementation of ASP flooding in other oilfields. After all, the study of ASP flooding enhanced oil recovery technology under low oil prices requires great foresight and determination.

Gelation Kinetics of Hydrogels Based on Acrylamide⁻AMPS⁻NVP Terpolymer, Bentonite, and Polyethylenimine for Conformance Control of Oil Reservoirs

Relatively smaller volumes of gelling systems had been used to address conformance problems located near the wellbore in oil reservoirs with harsh temperature and salinity conditions. These gelling systems were formulated with high concentrations of low-molecular-weight acrylamide-based polymers crosslinked with polyethylenimine (PEI). However, for in-depth conformance control, in which large gelant volumes and long gelation times were required, lower-base polymer loadings were necessary to ensure the economic feasibility of the treatment. In this study, a gelling system with high-molecular weight 2-acrylamido-2-methylpropane sulfonic acid (AMPS), N-vinyl-2-pyrrolidone (NVP), acrylamide terpolymer, and PEI, with the addition of bentonite as a filler, was formulated. The influence of the gelant formulation and reservoir conditions on the gelation kinetics and final gel strength of the system was investigated through bottle tests and rheological tests. The addition of clay in the formulation increased the gelation time, thermal stability, and syneresis resistance, and slightly improved the final gel strength. Furthermore, samples prepared with polymer and PEI concentrations below 1 wt %, natural bentonite, and PEI with molecular weight of 70,000 kg/kmol and pH of 11: (i) presented good injectivity and propagation parameters (pseudoplastic behavior and viscosity ~25 mPa·s); (ii) showed suitable gelation times for near wellbore (~5 h) or far wellbore (~21 h) treatments; and (iii) formed strong composite hydrogels (equilibrium complex modulus ~10–20 Pa and Sydansk code G to H) with low syneresis and good long-term stability (~3 to 6 months) under harsh conditions. Therefore, the use of high-molecular-weight base polymer and low-cost clay as active filler seems promising to improve the cost-effectiveness of gelling systems for in-depth conformance treatments under harsh conditions of temperature and salinity/hardness.

Assessment of two prop-2-enamide-based polyelectrolytes as property enhancers in aqueous bentonite mud

Large amounts of hydrocarbons are located in deeper formations where higher temperatures are experienced, hence designing a proper drilling fluid to tolerate such conditions has represented a challenging task for researchers in the field. The current work is focused on evaluating the effectiveness of poly(prop-2-enamide-sodium 2-acrylamido-2-methyl propane sulphonate-ethenyl ethanoate), designated as CP4 and poly(prop-2-enamide-sodium-prop-2-enoate-

Synthesis and characterization of hyperbranched associative polyacrylamide

HDPAM was synthesized by water free-radical copolymerization based on functional hyperbranched polyamide-modified ultrafine silica as functional monomer.