Hongjun Wu

In this study, three compositionally distinct condensate systems were tested to explore wax precipitation behaviors under variable temperature conditions. Multiple experimental approaches, including isothermal centrifugation for solid–liquid separation, gas chromatographic component quantification, SARA fractionation, and microscopic morphological observation, were comprehensively employed to investigate the temperature-dependent evolution of wax-precipitation mass fraction, precipitation rate, precipitate composition, and crystal microstructure. On this basis, the coupled effects of temperature and fluid composition on wax-dominated precipitation behaviors were systematically analyzed. The results indicate that temperature decline can reduce system internal energy and decrease the nucleation energy barrier of wax crystals. Such variations facilitate the precipitation of wax components and weaken the Brownian motion of newly formed solid particles, thereby simultaneously increasing the waxy precipitate mass fraction and precipitation rate. The compositional characterization of wax precipitates formed at different temperatures confirms that saturated hydrocarbons may serve as the predominant wax-forming component, and their abundance governs the final precipitation yield of the system in this study. Statistical analysis of the experimental data indicates that the proportion of precipitated-wax mass to the total wax content in the system rises with the increase in the asphaltene-to-resin content ratio. This indicates that asphaltenes may provide nucleation sites for wax-crystal growth and thereby facilitate wax precipitation, whereas resins could encapsulate crystal nuclei and produce a steric-hindrance effect to exert a certain inhibitory effect on wax-crystal precipitation. Furthermore, owing to differences in the solubilities of components with varying carbon numbers, low-carbon-number alkanes become prone to precipitate gradually as their precipitation conditions are satisfied during cooling. This corresponds to an increase in their proportion within precipitates, shifting the peak of the carbon-number-distribution curve of precipitates toward the low-carbon-number region and altering the SARA composition of systems. At the microscopic scale, the proportion of macrocrystalline wax crystals in precipitates increases as the temperature decreases, accompanied by an enlargement in the average wax-crystal size, which is consistent with the aforementioned rise in low-carbon-number-alkane content. This study aims at providing experimental data and theoretical support for evaluating the development and composition of wax precipitates at different wellbore conditions to a certain extent.

Wax deposition occurs to varying degrees in most oil and gas wells. The basic data of existing wax precipitation prediction models are mainly single-component wax experimental data based on the melting process of wax crystals during heating, which is quite different from the cooling crystallization process of wax in oil and gas production. Moreover, the published solubility test data of binary n-alkanes are mainly concentrated in the range of nC10–nC36, leaving existing thermodynamic models without available data for predicting the behavior of high-carbon alkanes. Based on the idea of wax crystallization and precipitation during cooling, this study experimentally determined the solid–liquid equilibrium solubilities of high-carbon n-alkanes (nC38, nC40, nC44, nC48 and nC50) with different concentrations in n-heptane, n-nonane and n-dodecane, as well as the crystallization parameters of pure substances, by using a DSC instrument. This effectively fills the gap in the basic physical property data of long-chain alkanes (more than nC36) and the cooling process in existing studies. In addition, we measured the crystallization parameters of pure high-carbon n-alkanes (nC38, nC40, nC44, nC48 and nC50) during cooling, including crystallization temperature, transition temperature, crystallization enthalpy and transition enthalpy under cooling conditions. The experimental data are in good agreement with the solubility predicted by the ideal solution model for the cooling process, with an average absolute percentage error of less than 10% and average solubility deviation generally within 0.078 mol%. This indicates that the ideal solution model has good accuracy for predicting the precipitation of n-alkane wax and n-alkane solvents. This study provides basic data for the prediction theory of paraffin precipitation.

This study investigates the use of fly ash to mitigate the long-term performance degradation of Portland cement-based sealing materials in high-salinity environments, such as those found in gas storage reservoirs. We systematically evaluated the evolution of material properties under different temperatures and curing periods. Our integrated methodology combining mechanical tests, microstructural analysis, and chloride migration assessment, reveals a multi-faceted mechanism by which fly ash enhances chloride resistance. The key findings demonstrate that reactive Al₂O₃ in fly ash promotes the formation of Friedel’s salt, increasing chemical chloride binding and reducing the chloride ingress rate in the Portland cement–Fly ash system (PFS) to only 26.6% of that in the Portland Cement system (PCS). Concurrently, the pozzolanic reaction consumes portlandite (Ca(OH)₂), forming stable C-A-S-H gel and refining the pore structure by filling interconnected channels. This nanoscale pore refinement decreased permeability by nearly an order of magnitude. After 90 days of curing in 90 °C saline solution, PFS achieved a compressive strength of 28.2 MPa and maintained an exceptionally low internal chloride content of 0.08 wt.%, demonstrating superior long-term durability. This work clarifies the synergistic mechanisms of fly ash modification and temperature effects, providing a theoretical basis for optimizing sealing materials for deep geological reservoirs and experimental support for the application of fly ash in high-temperature, high-salinity engineering environments.

Based on static scale inhibition experiments and molecular dynamics (MD) simulations, this study investigated the influence of concentration and temperature on the scale inhibition performance and adsorption behavior of the hydroxyphosphonic acid-based XCN scale inhibitor on calcite (104) surfaces. Experimental results demonstrate that XCN exhibits excellent inhibition efficiency against CaCO₃ scale, achieving 91.26% at 30 ppm and 60 °C. Further increasing the concentration to 35 ppm improves the inhibition rate by only 0.52%, a marginal gain attributable to the threshold effect. Performance improves with decreasing temperature, increasing from 91.26% at 60 °C to 96.92% at 30 °C. MD simulations reveal that the adsorption energy between XCN and calcite peaks at a specific molecular count (9 molecules), indicating optimal surface coverage. Radial distribution function analyses confirm chemisorption via Ca-O and Ca-H interactions within 1–3.5 Å, inducing lattice distortion that inhibits crystal growth. However, increasing temperature weakens adsorption and promotes molecular desorption, reducing inhibition efficiency. These findings provide molecular-level insights into the threshold and thermal behaviors of phosphonic acid scale inhibitors, supporting the optimized application of XCN in oilfield operations.

Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate repeatability Notably, formation damage is a primary consideration in treatment design—most dense gas reservoirs have a permeability of less than 1 mD, making them highly susceptible to damage by formation water, let alone viscous polymer gels. Constrained by well completion methods, gelant can only be bullheaded into deep gas wells in most scenarios. Due to the poor gas/water selective plugging capability of conventional gels, the injected gelant tends to enter both gas and water zones, simultaneously plugging fluid flow in both. Although several techniques have been developed to re-establish gas flow paths post-treatment, treating gas-producing zones remains risky when no effective barrier exists between water and gas strata. Additionally, most water/gas selective plugging materials lack sufficient thermal stability under high-temperature and high-salinity (HTHS) gas reservoir conditions, and their injectivity and field feasibility still require further optimization. To address these challenges, treatment design should be optimized using non-selective gel materials, shifting the focus from directly preventing formation water invasion into individual wells to mitigating or slowing water invasion across the entire gas reservoir. This approach can be achieved by placing large-volume gels along major water flow paths via fully watered-out wells located at structurally lower positions. Furthermore, the drainage capacity of these wells can be preserved by displacing the gel slug to the far-wellbore region, thereby dissipating water-driven energy. This study evaluates the viability of placing gels in fully watered-out wells at structurally lower positions in an edge-water drive gas reservoir to slow water invasion into structurally higher production wells interconnected via numerous microfractures and high-permeability streaks. The gel system primarily comprises polyethyleneimine (PEI), a terpolymer, and nanofibers. Key properties of the gel system are as follows: Static gelation time: 6 h; Elastic modulus of fully crosslinked gel: 8.6 Pa; Thermal stability: Stable in formation water at 130 °C for over 3 months; Injectivity: Easily placed in a 219 mD rock matrix with an injection pressure gradient of 0.8 MPa/m at an injection rate of 1 mL/min; and Plugging performance: Excellent sealing effect on microfractures, with a water breakthrough pressure gradient of 2.25 MPa/m in 0.1 mm fractures. During field implementation, cyclic gelant injections combined with over-displacement techniques were employed to push the gel slug deep into the reservoir while maintaining well drainage capacity. The total volumes of injected fluid and gelant were 2865 m³ and 1400 m³, respectively. Production data and tracer test results from adjacent wells confirmed that the water invasion rate was successfully reduced from 59 m/d to 35 m/d. The pilot test results validate that placing gels in fully watered-out wells at structurally lower positions is a viable strategy to protect the production of gas wells at structurally higher positions.