Key Laboratory of Drilling and Production Engineering for Oil and Gas, Hubei Province

The application of hydraulic fracturing stimulation technology to improve the productivity of unconventional oil and gas reservoirs is a well-established practice. With the increasing exploration and development of unconventional oil and gas resources, the associated geological conditions and physical properties are gradually becoming more and more complex. Therefore, it is necessary to develop technologies that can improve the development benefits to meet these challenges. In recent years, improving the effect of hydraulic fracturing stimulation in unconventional oil and gas reservoirs through the use of nanomaterials and technologies has attracted increasing attention. In this paper, we review the current status and research progress of the application of nanomaterials and technologies in various aspects of hydraulic fracturing in unconventional oil and gas reservoirs, expound the mechanism and advantages of these nanomaterials and technologies in detail, and provide future research directions. The reviewed literature indicates that nanomaterials and technologies show exciting potential applications in the hydraulic fracturing of unconventional reservoirs; for example, the sand-carrying and rheological properties of fracturing fluids can be significantly enhanced through the addition of nanomaterials. The use of nanomaterials to modify proppants can improve their compressive strength, thus meeting the needs of different reservoir conditions. The fracturing flowback fluid treatment efficiency and purification effect can be improved through the use of nanophotocatalysis and nanomembrane technologies, while degradable fracturing completion tools developed based on nanomaterials can effectively improve the efficiency of fracturing operations. Nanorobots and magnetic nanoparticles can be used to more efficiently monitor hydraulic fracturing and to accurately map the hydraulic fracture morphology. However, due to the complex preparation process and high cost of nanomaterials, more work is needed to fully investigate the application mechanisms of nanomaterials and technologies, as well as to evaluate the economic feasibility of these exciting technologies. The main research objective of this review is to comprehensively summarize the application and research progress of nanomaterials and technologies in various aspects of hydraulic fracturing in unconventional oil and gas reservoirs, analyze the existing problems and challenges, and propose some targeted forward-looking recommendations, which may be helpful for future research and applications.

Summary For conventional particles used for conformance control in fractured-vuggy reservoirs, large-size particles easily plug the wellbore area but have difficulty plugging the zone far from the wellbore, while small-size particles easily move in depth. In this study, fiber balls for bridging in fractured-vuggy reservoirs were developed by wrapping the fiber in the precrosslinked gel. Due to the influence of temperature and salinity in the formation, the gel degraded and the filamentous fibers were released. Then, the released fibers bridged in the fractures while reducing the safety risk of the injection process. As a water plugging agent, the fiber balls can decrease the conductivity in high-permeability fractures and increase the conductivity in low-permeability fractures, thus improving waterflooding efficiency and enhancing oil recovery. The plugging performance of fiber balls was evaluated by coreflooding experiments. The experimental results show that the optimal formulation of fiber balls is 7% acrylamide (AM) + 3% polyamino acid ester + 0.75% potassium persulfate (K2S2O8) + 4% polypropylene fiber + 4% glass fiber + 0.15% polyethylene glycol diacrylate (PDA) + 0.08% N,N-dimethyl acrylamide (MBA) + 0.1% polyacrylamide (PAM). The release time of fibers from the external gel is 42 to 57 hours, meeting the requirements of conformance control. According to the results of the performance evaluation, the larger the fracture width, the worse the bridging effect of fibers. Besides, the rule of “3/2 bridging” fiber was proposed: When the fiber length is 3/2 times the fracture width, the fiber has the strongest bridging and plugging ability. With the increase in fracture width, the fiber concentration needs to be increased to have a good bridging performance. The results of this study can provide a new idea for the technology of conformance control in fractured-vuggy reservoirs.

In nature, biomineralization is a common phenomenon, which can be further divided into authigenic and artificially induced mineralization. In recent years, artificially induced mineralization technology has been gradually extended to major engineering fields. Therefore, by elaborating the reaction mechanism and bacteria of mineralization process, and summarized various molecular dynamics equations involved in the mineralization process, including microbial and nutrient transport equations, microbial adsorption equations, growth equations, urea hydrolysis equations, and precipitation equations. Because of the environmental adaptation stage of microorganisms in sandy soil, their reaction rate in sandy soil environment is slower than that in solution environment, the influencing factors are more different, in general, including substrate concentration, temperature, pH, particle size and grouting method. Based on the characteristics of microbial mineralization such as strong cementation ability, fast, efficient, and easy to control, there are good prospects for application in sandy soil curing, building improvement, heavy metal fixation, oil reservoir dissection, and CO2 capture. Finally, it is discussed and summarized the problems and future development directions on the road of commercialization of microbial induced calcium carbonate precipitation technology from laboratory to field application.

Summary In this paper, a meshless numerical modeling method named mesh-free discrete fracture model (MFDFM) of fractured reservoirs based on the newly developed extended finite volume method (EFVM) is proposed. First, matching and nonmatching point cloud generation algorithms are developed to discretize the reservoir domain with fracture networks, which avoid the gridding challenges of the reservoir domain in traditional mesh-based methods. Then, taking oil/water two-phase flow in fractured reservoirs as an example, MFDFM derives the EFVM discrete scheme of the governing equations, constructs various types of connections between matrix nodes and fracture nodes, and calculates the corresponding transmissibilities. Finally, the EFVM discrete scheme of the governing equations and the generalized finite difference discrete scheme of various boundary conditions form the global nonlinear equations, which do not increase the degree of nonlinearity compared with those in the traditional finite volume method (FVM)-based numerical simulator. The global equations can be solved by the existing nonlinear solver in the FVM-based reservoir numerical simulator by only adding the linear discrete equations of boundary conditions, which reduce the difficulty of forming a general purpose MFDFM-based fractured reservoir numerical simulator. Several numerical test cases are implemented to illustrate that the proposed MFDFM can achieve good computational performance under matching and nonmatching point clouds, and for heterogeneous reservoirs, complex fracture networks, complex boundary geometry, and complex boundary conditions, by comparing the computational results of MFDFM with embedded discrete fracture model (EDFM). Thus, MFDFM retains the computational performances of the traditional mesh-based methods and can avoid the difficulties of handling complex geometry and complex boundary conditions of the computational domain, which is the first meshless numerical framework to model fractured reservoirs in parallel with the mesh-based discrete fracture model (DFM) and EDFM.

Summary To address the problems of steam channeling caused by the nonhomogeneity and fluid compatibility of the reservoir in heavy oil reservoirs and the permanent damage to the reservoir easily caused by traditional plugging agents, this study adopted polyaluminum chloride (PAC) as the main agent, urea as the coagulant promoter, and thiourea as the stabilizer and prepared a high-temperature-resistant (up to 350°C) degradable inorganic aluminum gel with excellent performance. Initially, scanning electron microscope (SEM) tests were conducted on gels with and without urea. Energy-dispersive X-ray spectroscopy (EDS)-mapping analysis of gels immersed in water with different mineralization levels for 5 days was then performed. The results revealed that the addition of urea led to a tighter and more complete crosslinked structure, significantly enhancing the mechanical strength of the gel. As water mineral content increased, the gel’s microstructure became denser and smoother. Metal cations on the cross-sectional surface increased gradually and distributed uniformly, further confirming the mechanism of the synergistic salt effect of soluble strong electrolytes and urea in strengthening the gel. Finally, the plugging and degradable properties of the gel were evaluated, and the results showed that the plugging percentage of the gel could still reach 97.6% after aging at 350°C for 30 days, and the gel had excellent plugging and diversion in dual sandpack experiments where the permeability ratio was less than 44. At 250°C, the degradation percentage of the gel was more than 98% at 5 days under the nonacid degradation system and 94% at 5 days under the acid degradation system. The gel showed good degradability and effectively reduced the damage to the reservoir.

Oil-well cement-based materials have inherent brittleness; therefore, they cannot be directly used to seal oil and gas wells for a long time. To improve the elasticity of oil-well cement-based composites, a flexible epoxy resin system was developed. The flexibility, TG, and SEM of the cured resin system were evaluated. At the same time, the resin was added to oil-well cement-based materials to improve its elasticity. The compressive strength and elastic modulus of resin cement stone were tested, and the microstructure was analyzed by XRD, TG, and SEM/EDS. The results showed that the structure of the cured resin is compact, the thermal decomposition temperature is 243.9 °C, and it can recover its original shape after compression. At the curing age of 28 days, the compressive strength of cement-based composites containing 30% resin decreased by 26.7%, while the elastic modulus significantly decreased by 63.2%, and the elasticity of cement-based composites was significantly improved. The formation of hydration products (e.g., calcium silicate hydrate, and calcium hydroxide) in the resin cement slurry is obviously lower than that of pure cement, which is the reason for the decrease in compressive strength. The flexible structure of polymer particles and polymer film formed by epoxy resin is distributed inside the cement stone, which significantly improves the elasticity of oil-well cement-based composites. The results of this paper are helpful for the design of elastic cement slurry systems.

Thermo-responsive nanocomposites have recently emerged as potential nanoplugging agents for shale stabilization in high-temperature water-based drilling fluids (WBDFs). However, their inhibitory properties have not been very effective in high-temperature drilling operations. Thermo-responsive Janus nanocomposites are expected to strongly interact with clay particles from the inward hemisphere of nanomaterials, which drive the establishment of a tighter hydrophobic membrane over the shale surface at the outward hemisphere under geothermal conditions for shale stabilization. This work combines the synergistic benefits of thermo-responsive and zwitterionic nanomaterials to synchronously enhance the chemical inhibitions and plugging performances in shale under harsh conditions. A novel thermo-responsive Janus nanosilica (TRJS) exhibiting zwitterionic character was synthesized, characterized, and assessed as shale stabilizer for WBDFs at high temperatures. Compared to pristine nanosilica (SiNP) and symmetrical thermo-responsive nanosilica (TRS), TRJS exhibited anti-polyelectrolyte behaviour, in which electrolyte ions screened the electrostatic attraction between the charged particles, potentially stabilizing nanomaterial in hostile shaly environments (i.e., up to saturated brine or API brine). Macroscopically, TRJS exhibited higher chemical inhibition than SiNP and TRS in brine, prompting a better capability to control pressure penetration. TRJS adsorbed onto the clay surface via chemisorption and hydrogen bonding, and the interactions became substantial in brine, according to the results of electrophoretic mobility, surface wettability, and X-ray diffraction. Thus, contributing to the firm trapping of TRJS into the nanopore structure of the shale, triggering the formation of a tight hydrophobic membrane over the shale surface from the outward hemisphere. The addition of TRJS into WBDF had no deleterious effect on fluid properties after hot-treatment at 190 °C, implying that TRJS could find potential use as a shale stabilizer in WBDFs in hostile environments.

With the maturity of waterflooded reservoirs, owing to serious heterogeneity, the fluid will channel through the thief zone, leading to considerable remaining oil unrecovered in the upswept area. To further enhance oil recovery (EOR) after waterflooding, the heterogeneous phase combination flooding (HPCF) was composed of a polymer, branched-preformed particle gel (B-PPG), and surfactant. For the sake of improving the economic efficiency, the influence of the injection scheme on the EOR of HPCF with an equal chemical agent cost was investigated by sand-pack flooding experiments. Then, visual plate sand-pack model flooding experiments were performed to study the swept area of HPCF under different injection schemes. Results demonstrated that the total EOR of HPCF under different injection schemes ranged from 33.5 to 39.3%. Moreover, the EOR of HPCF under the alternation injection (AI) scheme was the highest, followed by the concentration step change injection (CI) scheme, and that of the simultaneous injection (SI) scheme was the least. The visual flooding experimental results showed that the swept area of HPCF after waterflooding under the AI scheme was higher than that of the SI. Moreover, in view of qualitative analysis of remaining oil distribution, the EOR of AI of HPCF was higher than that of SI, which was consistent with the parallel sand-pack flooding results.

Abstract In the drilling industry, the demand for environmentally friendly additives with high thermal stability is increasing due to the dual factors of increasing environmental pressure and high-temperature oil layers. However, commonly used non-toxic and biodegradable additives, such as etherified modified starch, cannot withstand temperatures higher than 150 °C. Additionally, natural polymers with better thermal stability obtained through graft modification with sulfonated monomers face challenges in meeting the standards of toxicity and biodegradability. To address these technical problems, a novel graft and crosslink copolymer, St-AA/AM/NVP/MBA (SAANM), was synthesized from corn starch by combining graft modification with a non-sulfonated monomer and cross-linking modification. Laboratory evaluation results confirm that the thermal stability of SAANM in a nitrogen atmosphere was close to 300 °C, and it exhibits excellent temperature resistance up to 170 °C in bentonite-based mud, while also retaining the non-toxic and biodegradable characteristics of starch. The water-based drilling fluid (WBDF), added with SAANM, demonstrated outstanding rheological properties, fluid loss control performance, and environmental friendliness after aging at 170 °C and being polluted by high concentrations of NaCl or CaCl 2 . The successful application of SAANM in a high-temperature directional well in an offshore oil field confirms its potential for borehole cleaning and wellbore stability.

Pressure waves possess many significant applications in the oil and gas drilling engineering field, such as mud pulse telemetry (MPT) and measurement while drilling (MWD). The focus of this research is to study the pressure wave propagation and attenuation characteristics of wellbore liquid-phase flow in managed pressure drilling (MPD) by fast switching throttle valve (FSTV). First, a mathematical model of transient pressure wave propagation along the wellbore in both upstream and downstream directions is proposed in MPD by FSTV based on the one-dimensional transient flow theory. The model considering the frictional shear effect between the pipe walls is solved by utilizing the method of characteristics. Meanwhile, boundary conditions at the drill string inlet and annulus outlet, at the throttle valve, at the junction of drill bit, and at the reducer are adequately taken into account according to the actual situation of fluid flow. Second, a laboratory experiment of excited pressure waves in a vertical wellbore is conducted to measure the variation of the pressure fluctuation with different pump rates by FSTV. Comparing with the measurement result, the calculation result is discovered that the overall change is consistent, where the maximum absolute relative error at the peak of the pressure wave is only 4.5%. Finally, it further analyzes influential factors affecting the propagation and attenuation behaviors of wellbore pressure waves in liquid-phase flow based on the model. The results indicate that pressure waveforms present sinusoidal wave propagation, and pump rates, pressure wave speed, excitation time, fluid type, mud density, fluid viscosity, and borehole size exert varying degrees of influence on downhole pressure fluctuations. The proposed model achieves accurate quantitative interpretation and analysis of downhole pressure wave in MPD by FSTV, which has important significance for the realization of safe and efficient drilling.

In this study, numerous triaxial hydraulic fracturing experiments are performed in continental shale outcrop samples and artificial samples with similar properties to investigate the HF propagation behavior under single-cluster and multi-cluster fracturing treatments. The single-cluster fracturing experimental results show that the interlayer interface (IF) has a significant effect on the HF height containment, which tends to shear slip under conditions of low IF bonded strength, low vertical stress difference, low wellbore traversing layer strength and low q⋅μ value (the product of injection rate and fracturing fluid viscosity), resulting in the arrest of HF by the IF, and the vertical propagation of HF is hindered. Seven types of HF geometries were observed under the interference of multiple IFs, which could be classified into three categories in the vertical plane based on degree of connection with IFs, namely, simple fracture, small-scale fishbone-like fracture, and large-scale fishbone-like fracture. The multi-cluster fracturing experimental results indicate that the vertical propagation law of HF under multi-cluster fracturing is similar to single-cluster fracturing. Under the conditions of small cluster spacing and large number of perforation clusters, it is difficult for each perforation cluster to initiate HF evenly, and the middle perforation cluster is more difficult than outers. In addition, injection-pressure curves in theory can provide some useful information for HF geometries identification. But it is difficult to judge whether the HFs initiate evenly and develop uniformly at multiple perforation clusters by observing the injection fracturing curves because the evolution law of the injection-pressure curves under the simultaneous propagation of multiple HFs and the propagation of a single HF are similar.

Abstract As exploration and development to the ultra-deep layer continue to advance, bottom hole temperatures have gradually increased, aggravating acid corrosion of the downhole pipe string and greatly challenging the safety of reservoir reconstruction. Hydrochloric acid (HCl), an inorganic acid with strong acidity, is widely used in common acid systems in oil fields. Therefore, the prevention of corrosion by HCl under high temperature is an important task. In this study, we analyze the molecular structure, synergistic effect, and inhibition mechanism of imidazoline, Mannich base, quaternary ammonium salt, and other high-temperature HCl inhibitors and green inhibitors to explore the temperature resistance of inhibitors from the perspective of molecular microstructure and provide guidance for the development of ultra-high-temperature acidification inhibitors. Finally, the advantages and disadvantages of various HCl corrosion inhibitors are compared and summarized, and the knowledge gap and future research direction in the development field of high-temperature HCl corrosion inhibitors are pointed out.

The loss of drilling fluids often occurs during reservoir extraction in fractured formations, and the prediction of natural fracture loss rate is vital for controlling drilling fluids loss. However, the coupling of loss model to wellbore flow has rarely been considered. Based on the non-Newtonian fluid loss dynamics theory, this study considers Herschel–Buckley fluid and develops an updated numerical model to couple the loss of fracture with wellbore flow. The roughness of the fracture is characterized using the continuous random accumulation method. The coupling model is verified by field data, and its simulated results show the average relative and maximum relative errors were 4.76% and 12.8%, respectively. A linear throttle valve is introduced to simulate the effect of regulating wellhead back pressure and pump displacement on drilling fluids loss in managed pressure drilling, and the results indicate that the impact of regulating wellhead back pressure is better than that of pump displacement. This paper studies the pressure fluctuates of the fractured borehole breathing mechanism in detail and has proposed two possible scenarios that may cause borehole breathing. Increasing the wellhead back pressure can convert the overflow into loss, while reducing the wellhead back pressure by too much at once may also turn a loss into an overflow. The orthogonal experiment design is performed to study the influence of eight parameters on the loss rate, and the order of influence is as follows: fracture width, fluidity index, fracture area, consistency factor, yield stress, drilling fluids density, circulating displacement, and fracture dip.

Water alternating gas (WAG) flooding is a widely employed enhanced oil recovery method in various reservoirs worldwide. In this research, we will employ SiO2 nanofluid alternating with the CO2 injection method as a replacement for the conventional WAG process in oil flooding experiments. The conventional WAG method suffers from limitations in certain industrial applications, such as extended cycle times, susceptibility to water condensation and agglomeration, and ineffectiveness in low-permeability oil reservoirs, thus impeding the oil recovery factor. In order to solve these problems, this study introduces SiO2 nanofluid as a substitute medium and proposes a SiO2 nanofluid alternate CO2 flooding method to enhance oil recovery. Through the microcharacterization of SiO2 nanofluids, comprehensive evaluations of particle size, dispersibility, and emulsification performance were conducted. The experimental results revealed that both SiO2-I and SiO2-II nanoparticles exhibited uniform spherical morphology, with particle sizes measuring 10–20 nm and 50–60 nm, respectively. The SiO2 nanofluid formulations demonstrated excellent stability and emulsification properties, highlighting their potential utility in petroleum-related applications. Compared with other conventional oil flooding methods, the nanofluid alternating CO2 flooding effect is better, and the oil flooding effect of smaller nanoparticles is the best. Nanofluids exhibit wetting modification effects on sandstone surfaces, transforming their surface wettability from oil-wet to water-wet. This alteration reduces adhesion forces and enhances oil mobility, thereby facilitating improved fluid flow in the rock matrix. In the oil flooding experiments with different slug sizes, smaller gas and water slug sizes can delay the breakthrough time of nanofluids and CO2, thereby enhancing the effectiveness of nanofluid alternate CO2 flooding for EOR. Among them, a slug size of 0.1 PV approaches optimal performance, and further reducing the slug size has limited impact on improving the development efficiency. In oil flooding experiments with different slug ratios, the optimal slug ratio is found to be 1:1. Additionally, in oil flooding experiments using rock cores with varying permeability, lower permeability rock cores demonstrate higher oil recovery rates.

Summary The traditional drill-in fluid used to construct open holes does not mitigate problems that arise in subsequent completion operations and the risk of formation damage. In this work, a degradable solid-free drill-in fluid was designed with excellent direct flowback and degradation capabilities to reduce potential reservoir damage. A new type of viscosifier (XC-LT), as the key additive in the solid-free drill-in fluid, was prepared by modifying xanthan (XC) with maleic anhydride, and its phase transition temperature (Tm) was 20°C lower than that of XC alone. The XC-LT molecules in an aqueous solution were completely degraded after standing for 3 days, resulting in a clear solution with minimal residue. Additionally, in our proposed degradable solid-free drill-in fluid system, the stability of XC-LT could be improved significantly due to the existence of other additives, including filtrate reducer, monoethanolamine (MEA), potassium chloride (KCl), and sodium sulfite (Na2SO3). After aging for 3 days, the degradable solid-free drill-in fluid system constructed with XC-LT and other additives still had good rheological properties, and the rheological parameters, such as apparent viscosity (AV), plastic viscosity (PV), and yield point (YP), remained relatively stable, meeting the requirements for carrying cuttings in the drilling process. Its low shear rate viscosity (LSRV) was 30 900 mPa·s, and the system had good degradation performance after standing for a long time, which can reduce the flowback breakthrough pressure of oil and gas resources. The permeability recovery values (Kod/Ko) of the contaminated cores with the degradable solid-free drill-in fluid were greater than 94%, and the degraded drill-in fluid could fully flow back through the pore throats, reflecting an excellent reservoir protection performance. Finally, the degradable solid-free drill-in fluid system was applied to wells in the South China Sea. Compared with the adjacent wells using the solid-free drill-in fluid and gel-breaking fluid systems, the well production using our proposed degradable solid-free drill-in fluid system exceeded the anticipated production and was much greater than that of the adjacent wells. Our proposed degradable solid-free drill-in fluid system had good reservoir protection performance, and its application simplified the completion process.

For tight oil and gas reservoirs to form complex fracture networks with high conductivity and repeated treatment of old wells, temporary plugging and diverting fracturing technology has become one of the important stimulation methods. Previous articles have been carried out on different types of temporary plugging agents in fracture pressure rise law and placement shape, but studies on the permeability of temporary plugging cakes are relatively lacking. In this paper, the pressure rise law of five kinds of temporary plugging agent is studied by conventional fracture simulation device, and the permeability properties of temporary plugging cakes are studied by original design manufactured porous medium device. The results show that there are some differences between the permeability of temporary plugging cakes and the formation of pressure-bearing plugging cakes, the permeability is related to the types of plugging cakes, and the pressure rising law is related to the type and particle size distribution of temporary plugging material. The maximum length of DA-1, DA-2, DA-3 and KMS-D aggregates is 2.93 cm, 5.83 cm, 6.73 cm and 6.00 cm, and the minimum aggregate permeability is 23.88 mD, 19.19 mD, 15.13 mD and 36.97 mD.

The burnout rate is an important parameter in the combustion of pulverized coal. During the process of pulverized coal burnout, its radiation characteristics and the entire coal-fired boiler vary with the burnout rate, which is a very complex process and current research is not clear enough. This study proposes a new single particle pulverized coal burnout model, which incorporates pore volume correction to fit the density ratio and diameter ratio of multiple coal types with varying burnout rates as the theoretical basis. Using Mie theory, Jiaozuo coal particles are calculated average absorption and scattering efficiency in the band of 0.39 ∼ 16 μm, which is used as the basis for correcting particle emissivity and scattering factor. Then, through user defined function (UDF) in the simulation software, the particle radiation characteristics are modified from the original constants of 0.9 and 0.6 to linear and polynomial models that vary with the burnout rate. Not only do the spatial distribution rules of the coal-fired boilers radiation characteristics with the burnout rate of the furnace be obtained, but also the temperature distribution of the furnace under different particle radiation characteristics models is compared. The results show that the pulverized coal burnout model is consistent with the experimental results in literatures. High burnout rate corresponds to low mass concentration of furnace particles, and low absorption and scattering coefficients. Using the above model to calculate the particle emissivity and scattering factor that vary with the burnout rate, after UDF embedding, the error between the simulation results and the on-site cross-sectional temperature and thermal imaging detection decreases from 4.81 % to 2.59 %, reflecting the high accuracy and rationality of the burnout model and particle radiation characteristic correction method.

Oxygen-rich combustion is a new type of clean combustion technology with important application prospects. At present, there are few detailed analyses on the mechanism changes of soot formation under oxygen enrichment of propane. In this paper, the effects of oxygen-rich (O2/N2, O2/CO2) combustion on soot formation in the propane laminar flow coaxial jet diffusion flame were investigated by using the experiment and numerical simulation. The flame image was taken by a color (CCD) camera in the visible band, and the two-dimensional distribution of temperature and soot volume fraction in the flame was reconstructed. In numerical simulation, the soot production model considers a detailed description of nucleation via collisions among heavy polycyclic aromatic hydrocarbons, particle aggregation, polycyclic aromatic hydrocarbons condensation, surface growth and oxidation through the hydrogen abstraction acetylene addition mechanism. The results show that the experimental results were compared with the numerical simulation results, and the numerical simulation results predict the temperature and soot change of oxygen-rich flame well. With the increase in oxygen concentration, the peaks of soot and temperature in the two oxygen-rich atmospheres gradually increased. With the increase in oxygen concentration, the peaks of soot and temperature in the two oxygen-rich atmospheres gradually increased. Comparing the combustion mechanism changes of the two oxygen-rich combustion systems, it was found that the hydrogen abstraction acetylene addition mechanism was the main cause of soot generation. The OH oxidation is dominated near the fuel nozzle side, and O2 oxidation is dominant downstream. With the substitution of CO2 for N2, the chemical effect of CO2 reduces the flame temperature and inhibits the formation mechanism and oxidation mechanism of soot to some extent. This in turn leaded to a reduction in the amount of soot produced.

High Resolution Image Download MS PowerPoint Slide Increasing the rate of penetration (ROP) is an effective means to improve the drilling efficiency. At present, the efficiency and accuracy of intelligent prediction methods for the rate of penetration still need to be improved. To improve the efficiency and accuracy of rate of penetration prediction, this paper proposes a ROP prediction model based on Informer optimized by principal component analysis (PCA). We take the Taipei Basin block oilfield as an example. First, we use principal component analysis to extract data features, transforming the original data into low-dimensional feature data. Second, we use the PCA-optimized data to build an Informer model for predicting ROP. Finally, combined with actual data and using the recurrent neural network (RNN) and long short-term memory (LSTM) as baselines, we perform algorithm performance comparative analysis using root-mean-square error (RMSE), mean absolute error (MAE), and coefficient of determination ( R 2 ). The results show that the average MAE, RMSE, and R 2 of the PCA–Informer model are 9.402, 0.172, and 0.858, respectively. Compared with other methods, it has a larger R 2 and smaller RMSE and MAPE, indicating that this method significantly outperforms existing methods and provides a new solution to improve the rate of penetration in actual drilling operations.

High Resolution Image Download MS PowerPoint Slide To analyze the internal flow field and flow characteristics within the impeller of a centrifugal pump handling solid–liquid two-phase flow, FLUENT software was applied to numerically simulate the solid–liquid two-phase flow in two different impeller designs. Using the Re-Normalization Group (RNG) turbulence model, the velocity and pressure fields were compared and the performance of the solid–liquid centrifugal pump was predicted. The results showed that the numerical simulation closely matched experimental data, proving the feasibility and validity of the solid–liquid two-phase turbulence model used in this study, with considerable potential for engineering applications. The average pressure distribution across the flow channels of both impellers was similar. For the five-blade pump, when the particle size of d s ranges from 0.2 to 2 mm, the pump head decreases by 4.31%. While for the particle size of d s, as it varies from 1 to 4 mm, the pump head drops by 2.23%, but the head of the composite-blade impeller was higher than that of the five-blade impeller. When the volume fraction of solid particles remained constant, the efficiency of the pumps with different blade parameters showed significant variation with changes in particle size. When the particle size increases, the efficiency of the composite-blade pump decreases slowly. However, for the five-blade pump, when the particle size d s < 1 mm, its efficiency drops rapidly as the particle size increases. Neither pump could maintain relatively high efficiency under all operating conditions. Therefore, for solid–liquid two-phase centrifugal pumps, it is crucial to design and operate the pumps according to the specific properties of the slurry.