Conventional micron sealants are unable to effectively seal nanopores and fractures in shale formations, and the development of new nanomaterials has now become a major research focus to address the instability of shale gas wells. In this paper, oil-based drilling fluids (ODFs) sealants named SMEB (poly(styrene-methyl methacrylate-ethyl methacrylate-butyl acrylate)) were synthesized by free radical polymerization. The SMEB has been characterized by Fourier transform infrared spectroscopy (FTIR), laser scattering analysis (LSA), thermogravimetric analysis (TGA), and scanning electron microscopy (SEM). The effect of SMEB on the rheological properties of drilling fluids was evaluated by assessing the changes in the rheological parameters of ODFs before and after aging. In addition, the sealing performance of SMEB in ODFs was investigated by high-temperature, high-pressure (HTHP) fluid loss tests and HTHP dense core permeability tests. The results indicated that the particle size of SMEB ranged from 60.68 to 157.39 nm, with a median size of 89.62 nm. The initial decomposition temperature of SMEB was 334 degrees C, which was in line with the requirement of high-temperature resistance for materials used in shale gas wells. The addition of SMEB has minimal effect on the rheological properties of the drilling fluids and did not adversely affect its performance. At 150 degrees C and 3.5 MPa, the sealing efficiency of the simulated mud cake was 59.69% with a measured permeability of 0.77 x 10(-4) mD at a concentration of 0.5 wt % SMEB. Additionally, when 0.5 wt % SMEB was applied to artificial cores at 105 degrees C and 3.5 MPa, the sealing efficiency was as high as 86.70%, and the corresponding permeability was 0.48 x 10(-3) mD. SMEB demonstrated excellent sealing capabilities in both simulated mud cake and artificial cores, reducing and preventing drilling fluids filtrate flow into the formation. Therefore, SMEB can be applied to drilling fluids as a novel sealing agent and make a significant contribution to maintaining wellbore stability.

Nanosealing technology has become the key to overcoming the wellbore instability problem in deep and ultradeep shale formations. In this Article, the terpolymer poly(MM-EM-BM) was synthesized from methyl methacrylate, ethyl methacrylate, and butyl methacrylate by a Michael addition reaction. The poly(MM-EM-BM) nanoparticles were investigated by Fourier transform infrared spectroscopy, laser scattering analysis, and thermogravimetric analysis. The results imply that the particle size range of poly(MM-EM-BM) is between 33.90 and 135.62 nm and the average diameter is about 85.95 nm at room temperature, which can maintain excellent stability at 382.75 °C. The effects of poly(MM-EM-BM) on the properties of oil-based drilling fluids (OBDFs) were ascertained through experiments on the rheological performance, electrical stability, and high-temperature and high-pressure (HTHP) filtration loss. The results suggested that when the amount of added poly(MM-EM-BM) increases, the apparent viscosity, plastic viscosity, dynamic shear force, and demulsification voltage of the drilling fluids will increase correspondingly; in contrast, the HTHP filtration loss gradually decreased. When poly(MM-EM-BM) is added at 0.75%, the kinetic-to-plastic ratio of the drilling fluids is 0.24 and the filtration loss is 0.6 mL, showing excellent overall performance. The drilling fluids have a good rock-carrying ability and water loss wall-building property. The sealing performance and mechanism of poly(MM-EM-BM) were researched by the method of a sealing performance test under high temperature. The results indicated that the more poly(MM-EM-BM) used, the higher the sealing efficiency of the mud cake and the core as the sealing medium. When poly(MM-EM-BM) was added at 0.75%, the sealing rates of the mud cake and the core as the sealing medium reached the maximum sealing rates of 40.30% and 91.48%, respectively. When poly(MM-EM-BM) enters the core nanopore joint for a certain distance under formation pressure, a tight sealing layer will be formed to effectively prevent the entry of filtrate. Poly(MM-EM-BM) as a potential oil-based nanosealing agent is expected to solve the problem caused by wellbore instability in shale horizontal wells.

In this work, low molecular weight alkyl polyamine (tris(2-methylaminoethyl)amine (TSA), hexamethyltris(2-aminoethyl)amine (TTA), nonamethyltris(2-aminoethyl)amine (TQA)) with different functional groups and the same hydrophobic chain was synthesized using tris(2-aminoethyl)amine (TPA). X-ray diffraction, scanning electron microscopy, X-Photoelectron spectroscopy, transmission electron microscopy, contact angle, and density functional theory simulation were used to investigate the montmorillonite swelling inhibition mechanisms. The results of the experiments showed that a small amount of TPA, TSA, TTA, and TQA can significantly reduce the basal spacing of montmorillonite (Mt). The basal spacing of montmorillonite did not change with increasing the inhibitor concentration. The basal spacing of Mt-TPA, Mt-TSA, and Mt-TTA had some differences in the dry and wet states, but there was no difference in Mt-TQA. This observation indicated that TPA, TSA and TTA exhibited a three-dimensional spatial configuration in the lamellar spacing of montmorillonite, while TQA was inserted into the space of montmorillonite layer in a single flat layer. As more amine groups were substituted by the methyl groups, the spatial configuration of inhibitors changes from a three-dimensional to a two-dimensional planar structure. The higher the number of hydrogen atom substitutions in the primary amine group by methyl groups, the larger the contact angle, and the stronger the hydrophobic capacity except for the quaternary ammonium groups. The simulation results indicated that the higher the number of substitutions, the larger the adsorption energy. Therefore, inhibitors with a quaternary amine group would have better inhibition performance.

Partially hydrolyzed polyacrylamide (HPAM) is the most extensively used polymer for enhanced oil recovery due to its accessibility and low cost. However, HPAM shows inadequacies in high mineralization and high-temperature reservoirs. To solve this problem, a comb-like polymer with superior salt-resistance and stability named CHPAM was prepared via direct free-radical copolymerization of acrylamide (AM) and acrylic acid (AA) with the self-designed monomer (Acryloyl-MPEG-1000). The chemical structures of CHPAM and monomers were characterized by Fourier transform infrared spectroscopy (FT-IR) and nuclear magnetic resonance spectroscopy (NMR). Static light scattering (SLS) was adopted to measure the molecular weights of CHPAM and HPAM. The solution properties of CHPAM and HPAM were comparatively studied. It was found that CHPAM showed better thermal-salt stability and salt-resistance than HPAM, especially in Ca2+ solution. This work paves a new way for the preparation of novel polymers.

A graft-modified copolymer (cWL-g-A) was synthesized using Welan Gum (WLG), acrylamide, acrylic acid, and 0-20 via free-radical copolymerization to be well applied for enhanced oil recovery. The chemical structure of the copolymer was characterized by Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance spectroscopy (NMR), thermogravimetry (TG) and scanning electron microscopy (SEM). The long-term stability, rheology, adsorption, temperature and salt resistance of the copolymer were investigated. The cWL-g-A solution showed superior temperature and salt resistance in comparison with partially hydrolyzed polyacrylamide (HPAM), due to the hydrophobic association of main polymer chain. Particularly in high salinity (230,000 mg/L) solutions, cWL-g-A showed a better antiaging performance at three different temperatures (25, 50 and 65 degrees C). Oil recovery yielded by cWL-g-A was 14.18% higher than that yielded by HPAM, as known from polymer flooding tests. These results elucidated that cWL-g-A synthesized herein was superior to HPAM in high-salinity and medium-high temperature oil reservoirs.