Polylactic acid (PLA) diverters have been extensively applied in fluid diversion treatments to create temporary flow barriers and ensure uniform treatment. Because PLA diverters tend to gradually hydrolyze in aqueous solutions into lactic acids through ester bond cleavage, their diversion performance is influenced by the rate of their hydrolytic degradation, which strongly depends on particle size, pH levels, and temperature. The effects of these factors on the degradation rate of commercial PLA diverters remain underexplored. In this study we systematically characterize the effects of particle size, solution pH, and temperature on the hydrolysis rate of PLA diverters in aqueous media. We found that the size of diverter greatly affected its degradation rates, and the extent of this effect depended on the solution pH. The effects of solution pH were also strongly correlated with the shapes of diverters. Higher temperatures greatly accelerated hydrolysis and reduced induction periods. The gathered hydrolysis data aligns closely with a previously established kinetic model. The kinetic rate constants varied only slightly with diverter size but were strongly affected by solution pH and temperature. These insights enhance our understanding of the PLA diverter’s degradation behaviors under conditions relevant to various downhole environments and provide guidance for optimizing its field performance.

Summary Permeability is a critical parameter for characterizing the effectiveness of diverter packs in redirecting fluid flow to low-permeability zones during well stimulation. However, degradable diverting agents such as polylactic acid (PLA) are susceptible to hydrolytic degradation under downhole conditions, and the influence of this degradation on pack permeability remains poorly understood. In this study, we developed a reliable experimental setup and, for the first time, investigated how in-situ hydrolytic degradation affects the permeability of commercial PLA diverters of various shapes and sizes in a pH 7 solution at 90°C. Permeability was measured over time as the diverters degraded, and empirical correlations were established between the degree of degradation and pack permeability for each diverter type. The results revealed that degradation has a significant and geometry-dependent impact on permeability. Fiber-type diverters exhibited an exponential decline in permeability with increasing degradation. Bead-type diverters showed a moderate, linear decrease in permeability, while flake-type diverters exhibited the most substantial changes, following a biexponential decay pattern. Additionally, sample preparation methods, such as presoaking and stirring before packing, were found to be critical for achieving consistent and representative permeability measurements in fiber-based systems. These insights deepen our understanding of the behavior of PLA-based diverters under degradation and provide practical guidance for enhancing their effectiveness in field applications.

Accurately measuring and estimating the porosity and permeability of diverter packs is critical to effective fluid diversion during well stimulation. Existing models—primarily developed for particles with regular and smooth shapes—are unreliable for commercial diverters, which exhibit irregular shapes and complex surface characteristics. In this study, we systematically characterized the porosity and permeability of various types of binary diverter pack systems using commercial-grade diverters. Our results revealed a distinct V-shaped trend in porosity with an increasing volume fraction of larger particles. Although this general trend was captured by existing porosity models, the predicted porosity values were much lower than the experimentally measured values, primarily because of the incorrect assumptions about particle shape and size distribution used in these models. To overcome this, we developed an improved nonspherical packing model that more accurately captures these variations. Additionally, our permeability measurements showed that increasing the percentage of fine particles in binary diverter pack systems significantly reduced the pack's overall permeability. Comparisons with the existing models revealed that the predicted values were consistently higher than the measured one, primarily because of the model’ s failure to consider the key features of diverter packs such as pore structure, surface roughness, and wall effects. To address these shortcomings, we introduced a new permeability correlation with markedly improved prediction accuracy. Collectively, these findings expose the limitations of conventional models and emphasize the need for tailored predictive tools to enhance diverter design and stimulation effectiveness in practical applications.

Underground salt caverns are widely regarded as a promising solution for large-scale hydrogen storage because of their excellent sealing performance. However, understanding of hydrogen seepage in salt formations remains limited. To investigate hydrogen seepage behavior at the particle scale, a Discrete Element Method-Computational Fluid Dynamics (DEM-CFD) coupling methodology was developed to simulate hydrogen seepage in the cavern surrounding rock. The method captures bidirectional fluid-solid interaction together with porosity redistribution and particle displacement during seepage. A threshold pressure gradient and the Klinkenberg effect were included to capture the non-Darcy flow behavior of hydrogen. The effects of cyclic injection-withdrawal conditions and mudstone interlayers are further investigated. The results indicate that hydrogen seepage is strongly influenced by cyclic operation conditions, mudstone interlayers, and local fluid-solid response. The cumulative leakage under injection-withdrawal conditions remains below 1% after one year. More importantly, interlayer-salt interfaces can redistribute seepage pathways and significantly expand the seepage-affected zone within the salt formation. Neglecting this effect may lead to underestimation of the seepage extent and overestimation of the total leakage volume. These findings improve the understanding and evaluation of hydrogen seepage in interlayered salt cavern storage.

This work proposes a novel approach utilizing an oil-resistant, thermally stable self-generating foam system to achieve boundary lubrication drag reduction in thermal heavy oil transportation, focusing on the drag reduction characteristics of non-Newtonian self-generating foam and Newtonian oil phases under horizontal pipe co-flow conditions. Experiments were conducted in a 12-m-long, 25-mm-inner-diameter horizontal borosilicate glass pipe with roughened walls, measuring pressure gradients for co-flowing high-viscosity oil and foam at superficial velocities of 0.12-0.65 m/s (oil) and 0.06-0.63 m/s (foam). High-speed imaging identified stratified flow (ST) and eccentric core annular flow (ECAF) as dominant regimes across tested conditions. A three-zone two-phase model was developed for horizontal foam-oil flows, integrating the Carreau-Yasuda rheology of self-generated foam at 60 degrees C. The model demonstrates strong agreement with experimental data over broad operational ranges, confirming that full oil core encapsulation by foam determines the critical foam injection volume fraction for maximum drag reduction. Additionally, optimal oil transport efficiency was linked to specific oil core-to-pipe diameter ratios.

Wax crystallization at low temperatures greatly increases the viscosity of waxy oils and poses flow assurance challenges to their pipeline transportation. The conventional methods of lowering the viscosity of waxy oils, such as adding chemicals or externally heating the pipeline, are carbon-intensive and sometimes ineffective. Electrical treatment has emerged as a promising and low-carbon method to improve the cold flowability of waxy crude oils. While previous studies primarily focused on crude oil systems and highlighted the critical role of charged particles such as resins and asphaltenes in electrical treatment, this study systematically investigated the electrorheological behavior of model waxy oils composed solely of mineral oil and paraffin wax, without such charged particles. Using a rheometer equipped with an Electro-Rheology accessory, we characterized the changes in the oil's viscosity under DC electrical fields ranging from 0 to +/- 3 kV/mm. Significant viscosity reductions of up to 89 % were achieved. The viscosity reduction also strongly depended on the field direction, and negative electric fields generally result in higher reduction than those achieved by positive electric fields under the same field strength. Direct visualization by a high-resolution camera indicated that the migration of wax crystals toward electrodes is mainly responsible for the observed viscosity reduction, providing direct experimental evidence of the mechanisms supporting the negative electrorheology of waxy oils. This research greatly advances the mechanistic understanding of the interactions between wax crystals and electric fields, expanding the potential application of electrical treatments for flow assurance in pipelines.

Oil-water emulsions are prevalent in petroleum, chemical, and materials industries, where their rheological properties significantly impact processing efficiency. This review systematically examines the key factors influencing the apparent viscosity of oil-water emulsions, including oil composition, water characteristics, temperature, shear conditions, and emulsifier properties. It traces the evolution of viscosity prediction methodologies, encompassing conventional, complex, and Pickering emulsions, and assesses modeling approaches ranging from early theoretical frameworks to contemporary machine learning techniques. The reliability and applicability of these models are critically evaluated across various industrial contexts. Furthermore, the review identifies key challenges, research gaps, and prospective directions, emphasizing potential advancements in experimental strategies and modeling methodologies. While focusing on petrochemical emulsions, the insights and analytical approaches discussed are applicable to biological, medical, and other industrial systems, offering guidance for future research and practical implementation.

CO2 hydrate technology is attracting growing interest across a range of established and emerging fields, including offshore oil and gas flow assurance, secondary refrigeration, and carbon capture and sequestration. In most of these applications, CO2 hydrates exist in the form of a slurry, with solid hydrate particles dispersed in a liquid medium. The rheological and flow behaviors of CO2 hydrate slurries are critical to their successful applications. Compared to natural gas hydrates, CO2 hydrate research is relatively recent. Existing reviews primarily focus on thermodynamics and formation kinetics of CO2 hydrate, with limited attention to flow-related properties. To address this gap, we present a comprehensive review of four key areas central to CO2 hydrate slurry flow: (1) rheology, (2) interfacial tension between CO2 hydrate and the dispersion medium, (3) flow modeling, and (4) practical applications. We conclude with a discussion of the current challenges and future research directions. The insights provided in this review aim to support the development of efficient and scalable CO2 hydrate technologies.

During the high water cut period of oilfield development, conventional heated gathering and transportation systems incur exponentially rising energy consumption. The Wall sticking onset temperature (WSOT) is the key boundary parameter for low-temperature gathering and transportation. However, its predictive remains challenging owing to insufficient understanding of the wall sticking mechanism. Traditional WSOT predictive models commonly use Sauter mean diameter to simplify the droplet size distribution, ignoring the multiscale effect of the distribution width on the interfacial adhesion, which results in limited predictive accuracy under complex working conditions. In this study, we used a combination of cold finger experiments and microscopic observations to reveal for the first time the correlation mechanism between the WSOT of high water cut crude oil and the characteristics of the log-normal distribution of droplets in the oil-water mixture system. Based on the dynamic force balance theory, we innovatively proposed a dynamic correction method for the equivalent adhesion radius based on the dynamic distribution parameters (geometric mean and standard deviation), which breaks through the limitation of the traditional Sauter mean diameter to characterize a single scale only, and establishes a predictive model of WSOT considering the characteristics of droplet distribution. The model validation showed that the predictive error was <= +/- 4.802 %, which was significantly better than the model based on Sauter mean diameter. It is further found that regulating the water cut and shear rate can significantly reduce the WSOT by refining the droplet size and narrowing the distribution, which provides a new theoretical tool for the optimization of low-temperature gathering and transportation process.

In the late production stages of oil and gas fields, unheated oil gathering and transportation technology is widely used for high-water-content crude oil, significantly reducing energy consumption. However, the resulting lower pipeline temperatures can lead to wax deposition issues. In this study, a wax deposition prediction model was developed based on experimental and simulation data, and was further optimized using the Levenberg-Marquardt regression algorithm. The wax deposition characteristics of two high-water-content crude oils were investigated using a flow loop apparatus, and the effects of oil temperature, flow velocity, water content, and deposition time on wax deposition mass and rate were analyzed. CFD numerical simulations were conducted to examine the flow conditions within the pipeline, revealing trends in the radial temperature gradient and wall shear stress. The study found that wax appearance temperature, molecular diffusion, shear effects, encapsulation by water molecules, and the thickness of the deposition layer all influenced wax deposition process. Radial temperature gradients were found to be most sensitive to oil temperature, while wall shear stress was primarily affected by viscosity and velocity. Model validation demonstrated high consistency between the predicted results and experimental data, with average absolute errors of 7.73 % and 7.61 %, respectively. The relative errors between the predicted values of the model and the OLGA simulation results were within 15 %.

Partially hydrolyzed polyacrylamide (HPAM) is widely used for chemical enhanced oil recovery but its performance can be greatly reduced under harsh reservoir conditions. One proposed method of improving the performance of polymer flooding under reservoir conditions is the addition of functionalized nanoparticles (NPs). In this study, we systematically investigated the effects of adding hydrophobic or hydrophilic silica nanoparticles on the rheology, phase stability, and microstructure of HPAM solutions. Adding low concentrations of NPs slightly reduces the viscosity of the solutions but the presence of a high quantity of NPs (>0.5 wt %) makes the solution more viscous, elastic, and shear thinning. The results of dynamic light scattering reveal that these effects are mainly caused by the reversible formation of a large HPAM-NP network, which consists of HPAM chains weakly connected by NPs. When kept under static conditions, the NP-HPAM mixtures tend to undergo phase separation in a few days, but this issue is less likely to be a concern in field-scale polymer flooding during which the fluids are under constant flow. The findings of this study provide potential solutions to improve the performance of polymer flooding under high-salinity reservoir conditions.

Efficient transportation of anthropogenic CO2 from emission sources to storage sites or utilization facilities is vital to realize full-scale Carbon Capture, Utilization, and Storage (CCUS). The CO2 captured from emission sources is often contaminated with impurities that can significantly affect its thermophysical properties and flow behaviors during pipeline transportation. A holistic understanding of the impacts of these impurities is necessary to establish a cost-efficient and reliable CO2 pipeline transport system. In this study, we utilized an integrated thermophysical and fluid flow model and systematically analyzed the impurity effects of H-2, N-2, CH4, CO, O-2, Ar, SO2, H2S, and H-2 on the phase-envelopes, critical properties, density, viscosity, and pressure drop of CO2 streams. Each impurity was studied from zero to its highest concentration encountered in CCUS. The impacts of different impurities might be positive or negative to CO2 pipeline transportation depending on the system parameters being evaluated. H-2 generally produces the most negative impacts on transportation, greatly enlarging the two-phase region, most significant reductions in density and viscosity, and highest pressure loss. In contrast, H2S has a much milder effect on most system properties. In this paper, we also ranked the impacts of impurities on different system properties by grading the effect of each impurity at 5 vol % concentration and discussed their indications on CO2 pipeline transportation. These results offer practical insights into the design, operation, and management of CCUS CO2 pipelines nowadays and in the future.

Wax molecular diffusion coefficient is a crucial factor determining the wax deposition rate of waxy crude oil, but the calculation accuracy of the traditional Hayduk-Minhas and Wilke-Chang relations is unclear. The Couette wax deposition experiments of Changqing crude oil under different operating conditions (oil temperature, wall temperature, rotation speed and deposition duration) were carry out and find the traditional Hayduk-Minhas relationship will underestimate the wax molecular diffusion coefficient. To increase the calculation accuracy of wax molecular diffusion coefficient, a newly-developed diffusion laboratory apparatus coupled with the Differential Scanning Calorimeter (DSC) were utilized to evaluate the diffusion coefficient of C16, C18, C20, C22, C24 in n-alkane solutions at different temperatures (10, 15, 20, 25, 30,35, and 40 degrees C). Based on the experimental results, a novel high-precision correlation was put forward and the calculated results are in good agreement with the experimental results, the average relative error is within 3.0 %. The applied solvent of the n-alkane solutions is mineral oil and it has a complex composition. Therefore, the developed correlation can be used to evaluate the wax molecular diffusion coefficient in the real crude oil. The application of the new relationship will lead to more accurate wax deposition calculations.

Self-degradable diverters have gained increased popularity in well stimulation as an environmentally friendly and robust fluid diversion technology. As of now, limited data and conflicting information exist in the literature regarding the hydrolytic degradation rates of diverters under field-representative conditions, and knowing these rates is crucial for optimizing well stimulation designs. In this work, we systematically measured the degradation rates of commercial self-degradable diverters in aqueous solutions spanning a wide solution pH range of 0.3-13.6 and a wide temperature range of 60-110 degrees C. We first demonstrated that existing bottle degradation test protocols might return misleading results due to the alteration of solution pH by degradation products, and we developed a more reliable experimental protocol using buffer solutions instead. Using this procedure, we found that as the solution pH increased, the hydrolysis rate of diverters first decreased and then increased, with a minimal degradation rate at around pH = 4. Elevated temperatures yielded faster hydrolysis. The collected kinetic data fit reasonably well to a published kinetic model that was originally developed for pure polylactic acid in deionized water, with an R-2 value over 0.98 for all pH and temperature conditions. This comparison suggests that the model can be more widely applied to describe the degradation kinetics of commercial diverters over broad temperature and pH ranges. The test protocol, experimental data, and kinetic analysis in this work provide important guidance on improving the efficiency of fluid diversion and well stimulation operations.

Underground salt caverns have been used as gas storage for several decades. To explore the utilization of salt cavern in deep underground energy storage, one of the key issues is the mechanical characteristic of rock salt responses to high-temperature. In this study, the influence of temperature variations on rock salt is investigated through an integration of high-temperature uniaxial compression experimental test and high-temperature triaxial compression test. The characteristics of microcracks in rock salt are performed at different temperatures by DEM simulations. The results indicate the high temperature soften the strength of rock salt and induce thermal-cracking. The dilation point is analyzed from a microscopic perspective, and is interpreted as a turning point during the process, which the accumulated sliding energy gradually diffuse to the boundary energy. Additionally, a novel hybrid continuum-discrete coupling model is employed to reveal the mechanism of uncoordinated deformation of salt cavity surrounding wall subjected to operation conditions. The temperature influence exerts effect on temporal and spatial variations of salt cavity. The thermal damage evolution is prone to develop at interlayers, rather than the interface between the pure rock salt and interbedded impurities layer.

Two-phase pipe flow occurs frequently in oil & gas industry, nuclear power plants, and CCUS. Reliable calculations of gas void fraction (or liquid holdup) play a central role in two-phase pipe flow models. In this paper we apply the fractional flow theory to multiphase flow in pipes and present a unified modeling framework for predicting the fluid phase volume fractions over a broad range of pipe flow conditions. Compared to existing methods and correlations, this new framework provides a simple, approximate, and efficient way to estimate the phase volume fraction in two-phase pipe flow without invoking flow patterns. Notably, existing correlations for estimating phase volume fraction can be transformed and expressed under this modeling framework. Different fractional flow models are applicable to different flow conditions, and they demonstrate good agreement against experimental data within 5% errors when compared with an experimental database comprising of 2754 data groups from 14 literature sources, covering various pipe geometries, flow patterns, fluid properties and flow inclinations. The gas void fraction predicted by the framework developed in this work can be used as inputs to reliably model the hydraulic and thermal behaviors of two-phase pipe flows.

Underground gas storage is widely recognized as a crucial strategy in pursuing low-carbon and even zero-carbon emissions. This paper is motivated to investigate the injection process of underground gas storage. CO2 and H2 are prominent representative stored gases, also chosen as studied ones for their significant differences in physical properties, especially density. Simulations are conducted on models with different heterogeneities. Sensitive cases are designed with a vertical/horizontal well and under different injection strategies, to study the storage capacity of underground aquifers and the transportation process of injected gases during the injection process. Results show that the variations of injection mass and injection time of horizontal well systems have almost the same trends and values as those of the vertical well system for both H2 and CO2. As the injection rate increases, the effective storage efficiency (net injection mass friction) of H2 in the vertical well systems decreases while that in the horizontal increases, with relatively little difference for CO2. For dissolution trapping in a vertical well system, evaluation parameters (average concentration, dissolution mass, and fraction) increase as rising heterogeneity enhances the fingering gas-water contact but is relatively constant as the injection rate varies. Nevertheless, in horizontal well systems, they are relatively constant for CO2 but decrease for H2 with increasing injection rate, as less injection time limits the vertical gravity-induced migration, but are relatively constant with heterogeneity, as increased heterogeneity weakens the gravity-induced migration contact while improving the horizontal fingering contact. Besides, in these cases, the post-injection has a limited effect on the injected mass and overall storage efficiency and is not suggested due to its low time efficiency.

Paraffin wax deposition is a flow assurance issue that occurs frequently in subsea crude oil and gas condensate flowlines and pipelines. While some mitigation techniques involve coatings, most wax deposition in the oil and gas industry occurs on bare pipe walls made of various steel alloys. Previously, there has not been any investigation into the possibility of differences in the wax deposition that could be attributed to the different types of steel alloys, and this study set out to fill that gap. A cold finger apparatus with interchangeable fingers was used to generate deposits. Deposits were created from waxy model oils across several bulk oil temperatures and rotational speeds. To cover a wide array of materials, six different steels were tested: A2, A36, 1018, 4130, 304, and 316. These materials range from low-carbon steels to high-chrome content stainless steels. Each cold finger's surface was finished with the same process to create a roughness of 4.6 +/- 0.5 mm. Deposit mass, thickness, and composition all showed non-negligible differences between deposits formed on the steels investigated: masses varied by 5-15%, thicknesses varied by 30% or more, and deposit compositions were noticeably skewed. Alloy composition, contact angle, roughness, and thermal conductivity were discussed as possible indicators of the effects an alloy would have on wax deposition. These findings facilitate the comparison and interpretation of the results from wax research literature using different steel alloys as well as the design of laboratory wax testing that more closely resembles field conditions.