Molecular Insights into the Dual Promotion-Inhibition Effects of NaCl at Various Concentrations on the CO2 Hydrate Growth: A Molecular Simulation Study.

Hydrate-based CO2 storage in the ocean is considered a potential method for mitigating the greenhouse effect. Numerous studies demonstrated that NaCl exhibited the dual effects of promotion and inhibition in the nucleation and growth processes of CO2 hydrate, whose mechanisms remain unclear. In this study, the effects of NaCl at various concentrations on the CO2 hydrate growth and crystal are investigated. The independent gradient model based on Hirshfeld partition, electrostatic potential, and binding energy is conducted to study the interaction between ions and water molecules. The motion trajectories of ions are observed at the molecular level to reflect the impact of ion motion on hydrate growth. The results show that the influence of NaCl on hydrate growth depends on a delicate balance of dual promotion-inhibition effects. NaCl can combine more water molecules and provide a transport channel of CO2 to promote hydrate growth at low concentrations. Meanwhile, the promoting effects shift toward inhibition with increasing NaCl concentrations. In a word, this paper proposes a novel mechanism for the dual promotion-inhibition effects of NaCl on hydrate growth, which is significant for further research on hydrate-based CO2 storage in the ocean.

Acylated Inulin as a Potential Shale Hydration Inhibitor in Water Based Drilling Fluids for Wellbore Stabilization.

Shale hydration dispersion and swelling are primary causes of wellbore instability in oil and gas reservoir exploration. In this study, inulin, a fructo-oligosaccharide extracted from Jerusalem artichoke roots, was modified by acylation with three acyl chlorides, and the products (C10-, C12-, and C14-inulin) were investigated for their use as novel shale hydration inhibitors. The inhibition properties were evaluated through the shale cuttings hot-rolling dispersion test, the sodium-based bentonite hydration test, and capillary suction. The three acylated inulins exhibited superb hydration-inhibiting performance at low concentrations, compared to the commonly used inhibitors of KCl and poly (ester amine). An inhibition mechanism was proposed based on surface tension measurements, contact angle measurements, Fourier-transform infrared analysis, and scanning electron microscopy. The acylated inulin reduced the water surface tension significantly, thus, retarding the invasion of water into the shale formation. Then, the acylated inulin was adsorbed onto the shale surface by hydrogen bonding to form a compact, sealed, hydrophobic membrane. Furthermore, the acylated inulins are non-toxic and biodegradable, which meet the increasingly stringent environmental regulations in this field. This method might provide a new avenue for developing high-performance and ecofriendly shale hydration inhibitors.

Study on the Inhibition Mechanism of Hydration Expansion of Yunnan Gas Shale using Modified Asphalt.

Drilling fluids play an essential role in shale gas development. It is not possible to scale up the use of water-based drilling fluid in shale gas drilling in Yunnan, China, because conventional inhibitors cannot effectively inhibit the hydration of the illite-rich shale formed. In this study, the inhibition performance of modified asphalt was evaluated using the plugging test, expansion test, shale recovery experiment, and rock compressive strength test. The experimental results show that in a 3% modified asphalt solution, the expansion of shale is reduced by 56.3%, the recovery is as high as 97.8%, water absorption is reduced by 24.3%, and the compression resistance is doubled compared with those in water. Moreover, the modified asphalt can effectively reduce the fluid loss of the drilling fluid. Modified asphalt can form a hydrophobic membrane through a large amount of adsorption on the shale surface, consequently inhibiting shale hydration. Simultaneously, modified asphalt can reduce the entrance of water into the shale through blocking pores, micro-cracks, and cracks and further inhibit the hydration expansion of shale. This demonstrates that modified asphalt will be an ideal choice for drilling shale gas formations in Yunnan through water-based drilling fluids.

Preparation and Performance Evaluation of Ionic Liquid Copolymer Shale Inhibitor for Drilling Fluid Gel System.

An inhibitor that can effectively inhibit shale hydration is necessary for the safe and efficient development of shale gas. In this study, a novel ionic liquid copolymer shale inhibitor (PIL) was prepared by polymerizing the ionic liquid monomers 1-vinyl-3-aminopropylimidazolium bromide, acrylamide, and methacryloyloxyethyl trimethyl ammonium chloride. The chemical structure was characterized using fourier transform infrared spectroscopy (FT-IR) and hydrogen-nuclear magnetic resonance (H-NMR), and the inhibition performance was evaluated using the inhibition of slurrying test, bentonite flocculation test, linear expansion test, and rolling recovery test. The experimental results showed that bentonite had a linear expansion of 27.9% in 1 wt% PIL solution, 18% lower than that in the polyether amine inhibitor. The recovery rate of shale in 1 wt% PIL was 87.4%. The ionic liquid copolymer could work synergistically with the filtrate reducer, reducing filtration loss to 7.2 mL with the addition of 1%. Mechanism analysis showed that PIL adsorbed negatively charged clay particles through cationic groups, which reduced the electrostatic repulsion between particles. Thus, the stability of the bentonite gel systems was destroyed, and the hydration dispersion and expansion of bentonite were inhibited. PIL formed a hydrophobic film on the surface of clay and prevented water from entering into the interlayer of clay. In addition, PIL lowered the surface tension of water, which prevented the water from intruding into the rock under the action of capillary force. These are also the reasons for the superior suppression performance of PIL.

Effect of Low Gravity Solids on Weak Gel Structure and the Performance of Oil-Based Drilling Fluids.

Drilling cuttings from the rock formation generated during the drilling process are generally smashed to fine particles through hydraulic cutting and grinding using a drilling tool, and then are mixed with the drilling fluid during circulation. However, some of these particles are too small and light to be effectively removed from the drilling fluid via solids-control equipment. These small and light solids are referred to as low gravity solids (LGSs). This work aimed to investigate the effect of LGSs on the performance of oil-based drilling fluid (OBDF), such as the rheological properties, high-temperature and high-pressure filtration loss, emulsion stability, and filter cake quality. The results show that when the content of LGSs reached or even exceeded the solid capacity limit of the OBDF, the rheological parameters including the plastic viscosity, gel strength, and thixotropy of OBDF increased significantly. Furthermore, the filtration of OBDF increases, the filter cake becomes thicker, the friction resistance becomes larger, and the stability of emulsion of OBDF also decreases significantly when the concentration of LGSs reached the solid capacity limit of OBDF (6-9 wt% commonly). It was also found that LGSs with a smaller particle size had a more pronounced negative impact on the drilling fluid performance. This work provides guidance for understanding the impact mechanism of LGSs on drilling fluid performance and regulating the performance of OBDF.

Novel Modified Styrene-Based Microspheres for Enhancing the Performance of Drilling Fluids at High Temperatures.

Ensuring wellbore stability is of utmost importance for safety when drilling in deep formations. However, high temperatures severely disrupt the drilling fluid gel system, leading to severe stability issues within ultra-deep formations containing micropores. This study focused on the development of a polymer-based plugging material capable of withstanding high temperatures up to 200 °C. A kind of microsphere, referred to as SST (styrene-sodium styrene sulfonate copolymer), was synthesized with a particle size of 322 nm. Compared to polystyrene, the thermal stability of SST is greatly improved, with a thermal decomposition temperature of 362 °C. Even after subjecting SST to hot rolling at 200 °C for 16 h, the particle size, elemental composition, and zeta potential remained stable within an aqueous dispersion system. The results of core displacement and NMR tests demonstrate that SST considerably reduces the pore diameter with a remarkable plugging efficiency of 78.9%. Additionally, when drilling fluids reach 200 °C, SST still enhances drilling fluid suspension and dispersion, and reduces fluid loss by over 36% by facilitating the dispersion of clay particles, improving the gel structure of the drilling fluid, resisting clay dehydration, and promoting plugging. The development of SST provides valuable insights into the preparation of high-temperature-resistant microspheres and the formulation of effective plugging agents for deep-well drilling fluids.

Fracturing Fluid Polymer Thickener with Superior Temperature, Salt and Shear Resistance Properties from the Synergistic Effect of Double-Tail Hydrophobic Monomer and Nonionic Polymerizable Surfactant.

To develop high-salinity, high-temperature reservoirs, two hydrophobically associating polymers as fracturing fluid thickener were respectively synthesized through aqueous solution polymerization with acrylamide (AM), acrylic acid (AA), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), nonionic polymerizable surfactant (NPS) and double-tail hydrophobic monomer (DHM). The thickener ASDM (AM/AA/AMPS/NPS/DHM) and thickener ASD (AM/AA/AMPS/DHM) were compared in terms of properties of water dissolution, thickening ability, rheological behavior and sand-carrying. The results showed that ASDM could be quickly diluted in water within 6 min, 66.7% less than that of ASD. ASDM exhibited salt-thickening performance, and the apparent viscosity of 0.5 wt% ASDM reached 175.9 mPa·s in 100,000 mg/L brine, 100.6% higher than that of ASD. The viscosity of 0.5 wt% ASDM was 85.9 mPa·s after shearing for 120 min at 120 °C and at 170 s-1, 46.6% higher than that of ASD. ASDM exhibited better performance in thickening ability, viscoelasticity, shear recovery, thixotropy and sand-carrying than ASD. The synergistic effect of hydrophobic association and linear entanglement greatly enhancing the performance of ASDM and the compactness of the spatial network structure of the ASDM was enhanced. In general, ASDM exhibited great potential for application in extreme environmental conditions with high salt and high temperatures.

Preparation of Encapsulated Breakers for Polymer Gels and Evaluation of Their Properties.

A common problem associated with conventional gel breakers is that they can cause a premature reduction in gel viscosity at high temperatures. To address this, a urea-formaldehyde (UF) resin and sulfamic acid (SA) encapsulated polymer gel breaker was prepared via in situ polymerization with UF as the capsule coat and SA as the capsule core; this breaker was able to withstand temperatures of up to 120-140 °C. The encapsulated breaker was characterized using scanning electron microscopy (SEM), infrared spectroscopy (FT-IR), and thermogravimetric (TG) analysis. Meanwhile, the dispersing effects of various emulsifiers on the capsule core, and the encapsulation rate and electrical conductivity of the encapsulated breaker were tested. The gel-breaking performance of the encapsulated breaker was evaluated at different temperatures and dose conditions via simulated core experiments. The results confirm the successful encapsulation of SA in UF and also highlight the slow-release properties of the encapsulated breaker. From experimentation, the optimal preparation conditions were determined to be a molar ratio between urea and formaldehyde (nurea:nformaldehyde) of 1:1.8 for the capsule coat, a pH of 8, a temperature of 75 °C, and the utilization of Span 80/SDBS as the compound emulsifier; the resulting encapsulated breaker exhibited significantly improved gel-breaking performance (gel breaking delayed for 9 days at 130 °C). The optimum preparation conditions determined in the study can be used in industrial production, and there are no potential safety and environmental concerns.

Fabrication and property evaluation of calcium-oxide-loaded microcapsules during supplemental heat-based exploitation of natural gas hydrates.

The exploitation of natural gas hydrates (NGHs) by traditional methods is far lower than the commercial target. Calcium oxide (CaO)-based in situ supplemental heat combined with depressurization is a novel method for effectively exploiting NGHs. In this study, we propose an in situ supplemental heat method with the sustained-release CaO-loaded microcapsules coated with polysaccharide film. The modified CaO-loaded microcapsules were coated with polysaccharide films using covalent layer-by-layer self-assembly and wet modification process, with (3-aminopropyl) trimethoxysilane as the coupling agent and modified cellulose and chitosan as the shell materials. Microstructural characterization and elemental analysis of the microcapsules verified the change in the surface composition during the fabrication process. We found that the overall particle size distribution was within the range of 1-100 µm, corresponding to the particle size distribution in the reservoir. Furthermore, the sustained-release microcapsules exhibit controllable exothermic behavior. The decomposition rates of the NGHs under the effect of CaO and CaO-loaded microcapsules coated with one and three layers of polysaccharide films were 36.2, 17.7, and 11.1 mmol h-1, respectively, while the exothermic time values were 0.16, 1.18, and 6.68 h, respectively. Finally, we propose an application method based on sustained-release CaO-loaded microcapsules used for the supplemental heat-based exploitation of NGHs.

Study on the Low-Temperature Rheology of Polar Drilling Fluid and Its Regulation Method.

Drilling fluid is the blood of drilling engineering. In the polar drilling process, the ultra-low temperature environment puts high demands on the rheological performance of drilling fluids. In this paper, the effects of temperature, ice debris concentration and weighting agent on the rheological properties of drilling fluids were studied. It was found that the lower the temperature and the higher the ice debris concentration, the higher the drilling fluid viscosity, but when the ice debris concentration was below 2%, the drilling fluid rheology hardly changed. Secondly, the low temperature rheological properties of drilling fluid were adjusted by three different methods: base fluid ratio, organoclay, and polymers (dimer acid, polymethacrylate, ethylene propylene copolymer, and vinyl resin). The results showed that the base fluid rheological performance was optimal when the base fluid ratio was 7:3. Compared with polymers, organoclay has the most significant improvement on the low temperature rheological performance of drilling fluid. The main reason is that organoclay can transform the drilling fluid from Newtonian to non-Newtonian fluid, which exhibits excellent shear dilution of drilling fluid. The organoclay is also more uniformly dispersed in the oil, forming a denser weak gel mesh structure, so it is more effective in improving the cuttings carrying and suspension properties of drilling fluids. However, the drilling fluid containing polymer additives is still a Newtonian fluid, which cannot form a strong mesh structure at ultra-low temperatures, and thus cannot effectively improve the low-temperature rheological performance of drilling fluid. In addition, when the amount of organoclay is 2%, the improvement rate of the yield point reaches 250% at -55 °C, which can effectively improve the cuttings carrying and suspension performance of drilling fluid at ultra-low temperature.

A Thermal-Responsive Zwitterionic Polymer Gel as a Filtrate Reducer for Water-Based Drilling Fluids.

It is crucial to address the performance deterioration of water-based drilling fluids (WDFs) in situations of excessive salinity and high temperature while extracting deep oil and gas deposits. The focus of research in the area of drilling fluid has always been on filter reducers that are temperature and salt resistant. In this study, a copolymer gel (PAND) was synthesized using acrylamide, N-isopropyl acrylamide, and 3-dimethyl (methacryloyloxyethyl) ammonium propane sulfonate through free-radical polymerization. The copolymer gel was then studied using FTIR, NMR, TGA, and element analysis. The PAND solution demonstrated temperature and salt stimulus response characteristics on rheology because of the hydrophobic association effect of temperature-sensitive monomers and the anti-polyelectrolyte action of zwitterionic monomers. Even in conditions with high temperatures (180 °C) and high salinities (30 wt% NaCl solution), the water-based drilling fluid with 1 wt% PAND displayed exceptional rheological and filtration properties. Zeta potential and scanning electron microscopy (SEM) were used to investigate the mechanism of filtration reduction. The results indicated that PAND could enhance bentonite particle colloidal stability, prevent bentonite particle aggregation, and form a compact mud cake, all of which are crucial for reducing the filtration volume of water-based drilling fluid. The PAND exhibit excellent potential for application in deep and ultra-deep drilling engineering, and this research may offer new thoughts on the use of zwitterionic polymer gel in the development of smart water-based drilling fluid.

Comparative Studies on Thickeners as Hydraulic Fracturing Fluids: Suspension versus Powder.

To overcome the problems of long dissolution time and high investment in surface facilities of powder thickeners in hydraulic fracturing, a novel suspension of a thickener as a fracturing fluid was prepared using powder polyacrylamide, nano-silica, and polyethylene glycol by high-speed mixing. The suspension and powder were compared in terms of properties of solubility, rheological behavior, sand carrying, drag reduction, and gel breaking. The results showed that the suspension could be quickly diluted in brine within 5 min, whereas the dissolution time of powder was 120 min. The suspension exhibited better performance in salt resistance, temperature resistance, shear resistance, viscoelasticity, sand carrying, and drag reduction than powder. The powder solution was broken more easily and had a lower viscosity than suspension diluent. These improvements in properties of the suspension were due to the dispersion of nano-silica in the polymer matrix; the mobility of thickener chains was inhibited by the steric hindrance of the nano-silica. Nano-silica particles acted as crosslinkers by attaching thickener chains, which strengthened the network structure of the thickener solution. The presence of hydrogen bonds between the thickener matrix and the nano-silica restricted the local movement of thickener chains, leading to a stronger spatial network. Therefore, this novel suspension showed good potential for fracturing applications.

Synthesis of a Low-Molecular-Weight Filtrate Reducer and Its Mechanism for Improving High Temperature Resistance of Water-Based Drilling Fluid Gel System.

During the exploitation of deep and ultradeep oil and gas resources, the high-temperature problem of deep reservoirs has become a major challenge for water-based drilling fluids. In this study, a novel high-temperature-resistant filtrate reducer (LDMS) with low molecular weight was synthesized using N, N-dimethylacrylamide; sodium p-styrene sulfonate; and maleic anhydride, which can maintain the performance of a drilling fluid gel system under high temperature. Unlike the conventional high-temperature-resistant polymer filtrate reducer, LDMS does not significantly increase the viscosity and yield point of the drilling fluid gel systems. After aging at 210 °C, the filtrate volume of a drilling fluid with 2 wt% LDMS was only 8.0 mL. The mechanism of LDMS was studied by particle size distribution of a drilling fluid gel system, Zeta potential change, adsorption experiment, change of bentonite interlayer spacing, filter cake scanning electron microscope, and related theoretical analysis. The mechanism study revealed that LDMS could be adsorbed on the surface of bentonite particles in large quantities and intercalated into the interlayer of bentonite. Thus, it can improve the hydration degree of bentonite particles and the colloidal stability of the drilling fluid gel system, maintain the content of fine particles in the drilling fluid gel system, form a compact mud cake, and significantly reduce the filtrate volume of the drilling fluid gel system. Therefore, this work will promote the application of a low-molecular-weight polymer filtrate reducer in high-temperature-resistant water-based drilling fluid gel systems.

Improving the Weak Gel Structure of an Oil-Based Drilling Fluid by Using a Polyamide Wax.

Oil-based drilling fluids (OBDFs) are widely used, but there are common problems associated with them, such as low yield point and poor cutting-carrying and hole cleaning ability. In this paper, a polyamide wax (TQ-1) was synthesized from dimeric acid and 1,6-hexanediamine to improve the weak gel structure of OBDFs. The TQ-1 was characterized by Fourier transform infrared spectroscopy (FTIR) and thermogravimetric analysis (TGA). Then the effect of the TQ-1 on the stability of the water-in-oil emulsion was studied by sedimentation observation, stability analysis, an electrical stability test, and particle size measurement. The effect of the TQ-1 on the rheological properties of the water-in-oil emulsion was analyzed by viscosity vs. shear rate test and the three-interval thixotropic test. Finally, the performance of the TQ-1 in OBDFs was comprehensively evaluated. The experimental results showed that the initial thermal decomposition temperature of the TQ-1 was 195 °C, indicating that the TQ-1 had good thermal stability. After adding the TQ-1, the emulsion became more stable since the emulsion stability index (TSI) value decreased when the emulsions were placed for a period of time and the demulsification voltage was increased. The TQ-1 could form a weak gel structure in the water-in-oil emulsions, which made the emulsions show excellent shear thinning and thixotropy. TQ-1 can improve the demulsification voltage of OBDFs, greatly improve the yield point and gel strength, and largely reduce the sedimentation factor (SF). In addition, TQ-1 has good compatibility with OBDFs, and in our study the high-temperature and high-pressure (HTHP) filtration decreased slightly after adding the TQ-1. According to theoretical analysis, the mechanism of TQ-1 of improving the weak gel structure of OBDFs is that the polar amide group can form a spatial network structure in nonpolar solvents through hydrogen bonding.

Polymer Gels Used in Oil-Gas Drilling and Production Engineering.

Polymer gels are widely used in oil-gas drilling and production engineering for the purposes of conformance control, water shutoff, fracturing, lost circulation control, etc. Here, the progress in research on three kinds of polymer gels, including the in situ crosslinked polymer gel, the pre-crosslinked polymer gel and the physically crosslinked polymer gel, are systematically reviewed in terms of the gel compositions, crosslinking principles and properties. Moreover, the advantages and disadvantages of the three kinds of polymer gels are also comparatively discussed. The types, characteristics and action mechanisms of the polymer gels used in oil-gas drilling and production engineering are systematically analyzed. Depending on the crosslinking mechanism, in situ crosslinked polymer gels can be divided into free-radical-based monomer crosslinked gels, ionic-bond-based metal cross-linked gels and covalent-bond-based organic crosslinked gels. Surface crosslinked polymer gels are divided into two types based on their size and gel particle preparation method, including pre-crosslinked gel particles and polymer gel microspheres. Physically crosslinked polymer gels are mainly divided into hydrogen-bonded gels, hydrophobic association gels and electrostatic interaction gels depending on the application conditions of the oil-gas drilling and production engineering processes. In the field of oil-gas drilling engineering, the polymer gels are mainly used as drilling fluids, plugging agents and lost circulation materials, and polymer gels are an important material that are utilized for profile control, water shutoff, chemical flooding and fracturing. Finally, the research potential of polymer gels in oil-gas drilling and production engineering is proposed. The temperature resistance, salinity resistance, gelation strength and environmental friendliness of polymer gels should be further improved in order to meet the future technical requirements of oil-gas drilling and production.

Nano-laponite/polymer composite as filtration reducer on water-based drilling fluid and mechanism study.

In drilling deep complex formations, most drilling fluid additives have insufficient temperature and salt tolerance, resulting in the decline of drilling fluid performance. This study used 2-acrylamide-2-methylpropane sulfonic acid, acrylamide, dimethyl diallyl ammonium chloride and modified nano-laponite to synthesize a nanocomposite filtrate reducer (ANDP) with excellent temperature and salt resistance, which can maintain the performance of drilling fluid. The structure of ANDP was analysed by a transmission electron microscope and an infrared spectrometer. The thermal stability of ANDP was studied by thermogravimetric analysis. The performance of ANDP was evaluated in a water-based drilling fluid. The mechanism was analysed per clay particle size distribution, Zeta potential, filter cake permeability and scanning electron microscopy imaging. The results show that ANDP has good thermal stability and the expected molecular structure. The filtration of freshwater drilling fluid after ageing at 200°C is 10.4 ml and that of saturated brine drilling fluid is 6.4 ml after ageing at 150°C. Mechanism analysis suggests that the ANDP increases the thickness of clay particle hydration layer and maintains the colloidal stability of the drilling fluid. ANDP inhibits the agglomeration of clay particles and significantly reduces the filtration by forming dense mud cake.

Nano-Modified Polymer Gels as Temperature- and Salt-Resistant Fluid-Loss Additive for Water-Based Drilling Fluids.

With the continuous exploration and development of oil and gas resources to deep formations, the key treatment agents of water-based drilling fluids face severe challenges from high temperatures and salinity, and the development of high temperature and salt resistance filtration reducers has always been the focus of research in the field of oilfield chemistry. In this study, a nano-silica-modified co-polymer (NS-ANAD) gel was synthesized by using acrylamide, isopropylacrylamide, 2-acrylamide-2-methyl propane sulfonic acid, diallyl dimethyl ammonium chloride, and double-bond-modified inorganic silica particles (KH570-SiO2) through free radical co-polymerization. The introduction of nanotechnology enhances the polymer's resistance to high temperature degradation, making it useful as a high-temperature-resistant fluid loss reducer. Moreover, the anions (sulfonates) and cations (quaternary ammonium) enhance the extension of the polymer and the adsorption on the surface of bentonite particles in a saline environment, which in turn improves the salt resistance of the polymer. The drilling fluids containing 2.0 wt% NS-ANAD co-polymer gels still show excellent rheological and filtration performance, even after aging in high temperature (200 °C) and high salinity (saturated salt) environments, showing great potential for application in deep and ultra-deep drilling engineering.

A Temperature-Sensitive Polymeric Rheology Modifier Used in Water-Based Drilling Fluid for Deepwater Drilling.

Rheology modifiers are essential for the flat rheology of water-based drilling fluids in deepwater. The low temperature thickening of deepwater water-based drilling fluids results in dramatic rheological changes in the 20-30 °C range. To address such problems, NIPAM with a self-polymerized product LCST of 32-35 °C was selected as the main body for synthesis. While introducing the hydrophilic monomer AM to enhance the thickening properties, the hydrophobic monomer BA was selected to reduce the LCST of the product. In this paper, a temperature-sensitive polymeric rheology modifier (PNBAM) was synthesized by emulsion polymerization using N-isopropyl acrylamide, acrylamide, and butyl acrylate as monomers. The PNBAM was characterized using infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA), and nuclear magnetic resonance hydrogen spectroscopy (NMR). The rheological properties, temperature resistance, and salt resistance of PNBAM in the base fluid (BF) were tested. The performance of PNBAM in the drilling fluid system was also evaluated, and a water-based drilling fluid system of flat rheology for deepwater was formulated. The rheological modification mechanism of PNBAM was analyzed by turbidity analysis, particle size analysis, and zeta analysis. Experimental results show that PNBAM has good rheological properties. PNBAM is temperature resistant to 150 °C, salt-resistant to 30 wt%, and calcium resistant to 1.0 wt%. PNBAM also has good flat rheology characteristics in drilling fluid systems: AV4°C:AV25°C = 1.27, PV4°C:PV25°C = 1.19. Mechanistic analysis showed that the LCST (Lower Critical Solution Temperature) of 0.2 wt% PNBAM in an aqueous solution was 31 °C. Through changes in hydrogen bonding forces with water, PNBAM can regulate its hydrophilic and hydrophobic properties before and after LCST, which thus assists BF to achieve a flat rheological effect. In summary, the temperature-sensitive effect of PNBAM has the property of enhancing with increasing temperature. While the tackifying effect of conventional rheology modifiers diminishes with increasing temperature, the temperature-sensitive effect of PNBAM gives it an enhanced thickening effect with increasing temperature, making it a more novel rheology modifier compared to conventional treatment additives. After LCST, compared to conventional rheology modifiers (XC), PNBAM has a more pronounced thermo-thickening effect, improving the main rheological parameters of BF by more than 100% or even up to 200% (XC less than 50%). This contributes to the flat rheology of drilling fluids. PNBAM has good application prospects and serves as a good reference for the development of other rheology modifiers.

Types and Performances of Polymer Gels for Oil-Gas Drilling and Production: A Review.

Polymer gels with suitable viscoelasticity and deformability have been widely used for formation plugging and lost circulation control, profile control, and water shutoff. This article systematically reviews the research progress on the preparation principle, temperature resistance, salt resistance, and mechanical properties of the ground and in situ crosslinked polymer gels for oil-gas drilling and production engineering. Then, it comparatively analyzes the applicable conditions of the two types of polymer gel. To expand the application range of polymer gels in response to the harsh formation environments (e.g., high temperature and high salinity), we reviewed strategies for increasing the high temperature resistance, high salt resistance, and rheological/mechanical strengths of polymer gels. This article provides theoretical and technical references for developing and optimizing polymer gels suitable for oil-gas drilling and production.

Improvement of Emulsion Stability and Plugging Performance of Nanopores Using Modified Polystyrene Nanoparticles in Invert Emulsion Drilling Fluids.

Drilling fluid invasion and pressure transmission caused by the development of micropores and fractures in shale oil and gas formations are the major factors contributing to wellbore instability during drilling using oil-based drilling fluids (OBFs). In this study, a modified polystyrene latex (MPL) material was synthesized through emulsion polymerization and was characterized using Fourier transform infrared spectroscopy (FTIR), thermogravimetric analysis (TGA), particle size analysis, scanning electron microscopy (SEM) observations, and contact angle testing. The influence of the MPL on the stability of a water-in-oil emulsion was analyzed via sedimentation observations and electrical stability tests. The effects of the MPL on the plugging mechanism of white oil and water-in-oil emulsions were evaluated using 0.1-1.0 µm micro-porous filtration films. The experimental results revealed that the MPL has a favorable thermal stability, with an initial thermal decomposition temperature of 363°C, a median particle size (D50) of 233 nm, and a three-phase contact angle of 103.5°. The MPL can enhance the sedimentation stability of an emulsion to a considerable extent and can improve the electrical stability (ES) of the emulsion, which is conducive to the stability of OBFs. Due to the deformability of the MPL, it has a wide range of adaptations for micro-scale pores and fractures. In both the white oil and water-in-oil emulsions, the MPL can reduce the filtration loss through microporous membranes with pore sizes of 0.1-1.0 µm to within 10 ml. This paper details the methodology of the synthesis of nanomaterials that can effectively plug a formation's nanopores and fractures; thereby, stabilizing OBFs.