Sand Control Methods Research Articles

Research and Application of Chemical Sand Control without Blockage in WellBore

Abstract The main sand control methods for oil production wells in a certain Oilfield include mechanical filling sand control, artificial well bore reconstruction with coated sand, and phenolic resin sand control. Mechanical filling for sand control requires the well bore to be intact, with residual pipe columns in the well that cannot meet the testing fluid profile, and subsequent processing often requires major repairs; The construction pressure of artificial well bore is high, and the production of chemical resin sand control is significantly reduced. In order to ensure the consolidation strength, both sand control processes are under displacement operations, and the well bore above the top boundary of the perforated layer is fixed with a plug that needs to be drilled. Research on a new type of chemical sand control technology for well bore without blockage. By using biomass cellulose crystals with smaller particle size and resin in the sand fixing agent combination, the sand particles in the formation are well coated, and condensation reaction occurs to achieve the goal of sand control. The casing will not solidify to create well bore blockage, avoiding later drilling and plugging operations. The construction pressure is low, the damage to the casing is small, and it has a certain degree of selectivity. After sand control, the water content can be reduced by more than 10%. It is suitable for sand control operations in casing damage wells, casing change wells, high inclination wells, and horizontal wells, and can be used for packer construction. As of December 2023, there have been 8 on-site applications with a success rate of 100%, Average water content reduced by 13%, and a cumulative recovery of 2936 tons of oil production. This has safely and efficiently solved the sand control problem in complex well conditions.

Deep Eutectic Solvent as a New Zeta Potential Altering Chemical for Sand Agglomeration.

Fines migration can cause various issues, such as plugging of the sand screen and damage to tubings. There are two chemical sand control methods: consolidation and agglomeration. Consolidation works by injection of a solvent into the formation to harden over time and hold the sand in place, while agglomeration works by altering chemical properties of the sand surface to attract and clump up sand. Various chemicals have been used for research in sand control. Some chemicals for consolidation, mostly resins, have been effective in consolidating sand but may cause permeability impairment, which will reduce production. Some chemicals for agglomeration such as a polymer with amines have been less effective or are nonbiodegradable. In this work, a novel deep eutectic solvent (DES) and ionic polymer combination as a fines stabilizer is formulated in-house and tested through extensive experimental study. The development of chemicals is based on agglomeration principles which determine the range of zeta potential reduction that can be achieved to destabilize, coagulate, and flocculate the fine particles together with different combinations of DESs and ionic polymers tested systematically using the design of experiment (DoE) method. The chemicals are then tested for compatibility with reservoir fluids in the jar test. The optimized formulation is characterized by thermogravimetric analysis (TGA) for limit of temperature degradation and laser particle size analysis (LPSA) for the extent of particle size. The novelty of this work is the development of a greener and more cost-saving in-house DES and ionic polymer combination as a fines stabilizer chemical, which is effective for both injection or production wells after stimulation or enhanced oil recovery (EOR) treatments. Due to the tunable nature of the DES, the formulated chemical can be tailored for various reservoir conditions to cater to specific requirements.

Research on permeable self-restoring proppant for in-layer reinforcement and sand control

Weakly consolidated sandstone (WCS) is a common reservoir used in petroleum development. Owing to its loose structure, sand production and formation collapse frequently occur during oil and gas extraction, posing significant challenges in the petroleum industry. To address these issues, some researchers have proposed in-layer reinforcement sand control methods for weakly consolidated sandstones. To implement this approach, developing a permeability-self-restoring proppant (PSRP) for in-layer reinforcement is essential. The aim is to support the fractures created by fracturing, ensuring that the curable working fluid is not displaced and that the curable liquid does not infiltrate the voids of the PSRP, thereby preventing a substantial reduction in permeability. In this study, a new structure and principle for the PSRP are proposed. Polylactic acid (PLA) was selected as the filling material due to its alkaline solubility. The size and quantity of hollow microspheres were optimised based on the permeability of the consolidated body. The optimal microsphere size was determined to be 50–80 mesh, with an optimal dosage of 10%. Subsequently, the PSRP was developed and incorporated into a permeable curing liquid system prepared by other experts. The permeability of the obtained consolidated body was measured as 25.47 × 10−3 μm2 after 1 d and 22.46 × 10−3 μm2 after 7 d at 15 °C and 20 MPa. The compressive strength after 1 d was 6.88 MPa. Compared to conditions without PSRP addition, the permeability of the consolidated body increased by 35.12% after 1 d and by 134.47% after 7 d. This research lays the foundation for applying sand-control methods in in-layer reinforcement.

An Improved Artificial Electric Field Algorithm for Determining the Maximum Length of Gravel Packing in Deep-Water Horizontal Well

Gravel packing in deep-water horizontal wells is an effective and practical sand control method, which is a key technical method to ensure efficient exploitation of deep-water oil and gas. To ensure the successful implementation of gravel packing in deep water horizontal wells, it is crucial to carry out effective optimization design of packing parameters. This paper proposes a novel optimization design approach for gravel packing in deep-water horizontal wells. In the proposed approach, an optimization model is proposed for gravel packing in deep-water horizontal wells, in which the gravel packing length is regarded as the objective function. Then, an improved artificial electric field algorithm (IAEFA) is introduced for optimizing the key gravel packing parameters so as to determine the maximum gravel packing length. For a specific case study, we conducted optimization calculations for gravel packing in a deep-water horizontal well. Results of the case study demonstrate that the optimization design approach based on the IAEFA algorithm can effectively address the parameter optimization problem of deep-water horizontal well gravel packing. For the target well of the case study, the maximum packing length obtained by the IAEFA algorithm could reach 1000.22 m, and the corresponding 3 sets of optimal packing parameters were also obtained. In the scenario of optimal packing parameters, the total time of gravel packing in target well is 566.6 min, and the total amount of sand consumption is 54,050.94 lbs. The bottom hole pressure during the injection stage remains stable with about 9780 psi, then slowly rises from 9788 psi to 9837 psi in the α-wave packing stage, and rapidly increases from 9837 psi to 9986 psi in the β-wave packing stage. The proposed approach provides an efficient and practical optimization tool for the optimal design of gravel packing in deep water horizontal wells.

An experimental study of epoxy-based nanocomposite for chemical consolidation in a sandstone reservoir with high clay content

Sand production poses a substantial challenge in the oil and gas field, particularly in formations lacking the requisite strength to withstand pressure differentials during extraction. Many wells produce much less than their capacity due to the need to mitigate sand production and prevent well completion and wellhead erosion. The choice of sand control method depends on various factors, such as reservoir conditions, operational methods, and economic considerations, encompassing both mechanical and chemical approaches. In response to this challenge, this study investigates the application of a novel polymer nanofluid for chemical consolidation in clay-rich sandstone reservoirs, an area of exploration yet to be fully tapped. The research aims to assess the potential of polymer nanofluids as a promising solution for sand control in clay-rich reservoirs, with the overarching goal of bolstering well productivity and mitigating the adverse impacts of sand production. Conducted at a laboratory scale, the experiments involved the injection of 1 Pore Volume of consolidation fluid into sandstone cores with 15% and 30% clay content. Subsequently, the cores were subjected to reservoir temperature and pressure conditions for a period of 24 h. The obtained results show a significant enhancement in compressive strength, exceeding 700 psi, facilitated by the polymer nanofluid. Furthermore, permeability restoration reached approximately 89%, a notable improvement compared to preceding studies. Moreover, the introduction of foam injection rendered the core surface water-wet, suggesting potential advantages for reservoir management. These findings illuminate the promise of polymer nanofluids as an effective tool for sand control in clay-rich sandstone reservoirs.

Chemical sand production control: a review of materials, methods and characterization

Sand production is one of the challenges facing the oil industry. This paper reviews the latest research advances in chemical sand control and aims to provide a reference for related researchers. Firstly, the commonly used chemical sand control materials are introduced. Second, recent advances in chemical sand control are reviewed, including materials, methods, and processes. Third, laboratory methods for sand control research are presented. Finally, the gaps and challenges of chemical sand control materials are pointed out, and possible future directions for chemical sand control methods are envisioned.

A comprehensive review of cased hole sand control optimization techniques: Theoretical and practical perspectives

Cased hole sand control is a critical aspect of oil and gas well management, ensuring efficient production by mitigating sand production issues. This review presents a comprehensive review of cased hole sand control optimization techniques, offering theoretical insights and practical perspectives to enhance well productivity and longevity. The review encompasses various aspects, including the challenges of sand production, the importance of sand control, and the evolution of sand control techniques. Sand production in oil and gas wells can lead to equipment damage, wellbore instability, and reduced production efficiency. Effective sand control is thus essential to maintain well integrity and maximize hydrocarbon recovery. This review explores the fundamental principles of sand control, highlighting the key parameters influencing sand production, such as reservoir properties, fluid properties, and wellbore geometry. The review discusses traditional sand control methods, such as gravel packing and standalone screens, along with emerging technologies like expandable sand screens and autonomous inflow control devices. It evaluates the advantages and limitations of each technique, considering factors such as installation complexity, cost-effectiveness, and long-term reliability. Furthermore, the review delves into advanced sand control optimization strategies, including the use of modeling and simulation tools to predict sand production and optimize sand control design. It discusses the integration of data analytics and machine learning techniques for real-time monitoring and decision-making, enhancing sand control effectiveness and reducing operational risks. Practical case studies and field applications are presented to illustrate the implementation of sand control optimization techniques in real-world scenarios. These case studies highlight the challenges faced, the solutions implemented, and the outcomes achieved, providing valuable insights for industry practitioners and researchers. In conclusion, this review provides a comprehensive overview of cased hole sand control optimization techniques, emphasizing the importance of integrating theoretical knowledge with practical considerations to enhance sand control efficiency and maximize well productivity. his review paper will systematically analyze existing methodologies and the latest advancements in cased hole sand control treatments. It explores theoretical frameworks, compares practical outcomes, and discusses the implications of optimized frac geometries for reservoir performance enhancement across varied geological settings.

Sand control during gas production from marine hydrate reservoirs by using microbial-induced carbonate precipitation technology: A feasibility study

Sand production is one of the bottleneck problems restricting the safe and efficient production of marine hydrate reservoirs. Current research on this issue mainly focuses on the active sand control methods such as screen mesh and gravel packing, however, passive methods are rarely reported. In this study, a novel sand control strategy which uses microbial-induced carbonate precipitation (MICP) technology to reinforce hydrate reservoirs around the well is proposed. Based on the geological data of hydrate reservoirs in Japan, a reservoir-scale microbial reaction-migration model is established. The feasibility of MICP reinforcement to prevent sand production is demonstrated by the combinations of indoor triaxial testing, productivity prediction and microscopic sand production prediction. The results show that the MICP technology can effectively enhance reservoir strength, and has a negligible impact on the gas recovery. Although the calcium carbonate generated will slightly decrease the porosity and permeability, the cumulative gas production does not significantly decrease and the water extraction is also prevented. Most importantly, the amount of sand production can sharply reduce because of the cementation of calcium carbonate among sand particles. Additionally, the effectiveness and applicability can be improved by selecting appropriate bacteria fixation methods and grouting pressure at different stages.

Sand control mechanism of radial well filled with phase change material in hydrate reservoir

Radial well filled with phase change material has been proposed as a novel sand control method for hydrate exploitation. In order to reveal the sand control mechanism, CFD-DEM coupling method is applied to simulate the migration, settlement, and blockage processes of sand particles in the radial well. The obtained results indicate that three scenarios have been recognized for sand particles passing through sand control medium, based on the diameter ratio of sand control medium to sand particle (Dd): fully passing (Dd = 8.75–22.5), partially passing and partially blocked (Dd = 3.18–5.63), and completely blocked (Dd = 2.18–3.21). After being captured by the sand control medium, sand particles can block pores, which increases fluid flow resistance and causes a certain pressure difference in the radial well. The pressure in the radial well should be lower than the hydrate phase equilibrium pressure during sand control design, for the purpose of promoting hydrate decomposition, and sand capture. The length of the radial well should be optimized based on the reservoir pore pressure, production pressure difference, bottom hole pressure, and the pressure gradient in the radial well. It should be noticed that the sand control medium leads to a decrease in permeability after sand particles captured. Even the permeability is reduced to several hundred millidarcy, it is still sufficient to ensure the effective flow of gas and water after hydrate decomposition. Increasing fluid velocity reduces the blocking capacity of the sand control medium, mainly because of deterioration in bridging between sand particles.

Sandstone chemical consolidation and wettability improvement using furan polymer-based nanofluid

The oil and gas industry faces a challenge in meeting global energy demand due to sand production in unconsolidated or semi-consolidated reservoirs, leading to equipment wear, production instability, and significant financial burdens. Mechanical and chemical sand control methods are being used among which chemical sand consolidation techniques have emerged as a promising solution. In this research, furan polymer-based nanofluid is investigated as a chemical consolidant to explore its intriguing properties and characteristics and how the quantity of nanoparticles influences the fundamental properties of curing resin and wettability while pioneering a groundbreaking approach to enhancing regaining permeability. According to the findings, a substantial boost in core compressive strength has been achieved as well as an impressive increase in re-permeability, especially for the foam injection case, by the meticulous optimization of nanofluid composition. The results include a remarkable regain permeability of 91.37%, a robust compressive strength of 1812.05 psi, and a noteworthy 15.32-degree shift towards water-wet wettability. Furthermore, silica nanoparticles were incorporated to enhance the thermal stability of the fluid, rendering it more adaptable to higher temperatures. Therefore, Furan polymer-based nanofluid is not only expected to present a solution to the challenge of sand production in the oil and gas industry but also to provide operational sustainability.

Experimental Study of Sand Migration under Distinct Sand Control Methods during Gas Hydrate Decomposition by Depressurization

Experimental Study of Sand Migration under Distinct Sand Control Methods during Gas Hydrate Decomposition by Depressurization

RIGLESS WELL INTERVENTION AND SAND CONSOLIDATION CHEMICAL APPLICATION TO SOLVE SAND PROBLEM OF ABC-2 WELL IN X FIELD

The decline in well production due to sand problems is the biggest challenge in a field that has been producing for a long time, especially in mature fields. In addition, and problems are also able to damage both the downhole and surface equipment of a well. Creating the right job design for sand cleanout and sand control is absolutely necessary to solve this problem. Rig less well intervention with coiled tubing is used to optimize this process. The sand cleanout job design is created using Insite for Well Intervention (IWI) software to create the right job design. In addition, a sand control method with sand consolidation chemicals will be applied to prevent the recurrence of sand problems after the well has been cleaned. The findings of the study indicate that the proper job design is able to clean the sand to target depth and restore the production of the ABC-2 wells to its pre-sand problem level. All factors, including sieve analysis, well data, coiled tubing data, and sand consolidation chemical, are taken into consideration during job design. Therefore, the sand issue in another mature well at the X field can be solved using this approach

Comparative Studies and Analyses of the Different Mechanical Sand Control Systems: A Case Study of a Well Completed in the Niger- Delta of Nigeria

Abstract: Sand production problems are as old as oil drilling itself. It is argued to be the oldest problem plaguing the oil industry. This phenomenon leads to high economic losses in oil and gas production. If the passive methods of sand control of selective and oriental perforations fail, the active methods which involve the chemical and mechanical methods are called into play. This project work compares four mechanical sand control methods; Cased-Hole Gravel Pack, Wire-Wrapped Screens, Pre-Packed Screens and Slotted Liner. It studies the effectiveness of each system, total skin offered and their effects on well productivity. As a control, the data of a well completed without any sand control system in place in the Niger-Delta region of Nigeria was obtained. the IPR/VLP plots were made and the flow efficiencies were calculated. The well was later simulated with the four cases mentioned above and the total skin and flow efficiencies calculated. It was discovered that the flow efficiencies showed a reduction due to the installation of the sand control tools and the skin offered by each sand control system. The flow efficiencies dropped from 0.476 025 to 0.475 977 for Wire-wrapped Screen, 0.475 930 for Cased-Hole Gravel Pack, 0.475 914 for Pre-Packed Screen and finally 0.052 890 for the Slotted Liner. The drops in flow efficiencies were validated by the increasing values of total skin factors from 0 for No Sand Control System, 0.000 484 86 for Wire-Wrapped Screen, 0.002 359 for Pre-Packed Screen, 1.76 for Cased-Hole Gravel Pack and 49.82 for The Slotted Liner. Parameters as Absolute Open Flow Potential (AOFP), Productivity Index (P.I.), Total Skin Value and Liquid (Oil) Production Rate showed that the Wire-Wrapped Screen was the best sand control solution for the given well

Study on Erosion Model Optimization and Damage Law of Coiled Tubing

Coiled tubing (CT) is used as a velocity string to transport high-velocity gas in drainage gas recovery technology. Sand particles flowing at high speed can cause serious erosion of the pipe wall. Long-term erosion wear leads to the degradation of the string strength and can even cause local perforation. In order to study the erosion wear problem of CT, a gas–solid erosion experimental device was established for a full-size pipe with different radii of curvature. A 3D laser confocal technique was used to examine and characterize the microscopic erosion morphology of the inner wall of the CT. The CFD erosion model was selected based on the erosion test data of the inner wall of the CT, and the erosion results of the Finnie model show minimal error and good agreement compared with other models. The average value of the error of the maximum erosion rate at different radii of curvature is 8.3%. The effect of the radius of curvature, gas velocity and solid particle size on the maximum erosion rate of the inner wall of the CT was analyzed based on the Finnie model. The results reveal that erosion wear occurs on the inner wall of the CT’s outer bend. As the radius of curvature is reduced, the maximum erosion rate and area increase, and the position of the maximum erosion rate gradually shifts toward the inlet. The maximum erosion rate is positively correlated with the gas flow rate. However, as the particle size increases, the maximum erosion rate shows a trend of first increasing, then decreasing and finally stabilizing, with a critical particle size of 200 μm. This study can provide theoretical guidance and methods for improving the service life of CT. The erosion rate of the tubing in old wells can be reduced by controlling production and employing appropriate sand control methods, while the erosion rate of tubing in new wells can be reduced by adjusting the wellbore trajectory.

Investigating the Impact of Sieve Analysis on the Choice of Gravel Pack Design for Wells in Unconsolidated Sandstone Formations in the Niger Delta

Sand production is major problem for the oil and gas industry and solutions to this problem is a continuous process as new challenges arise with time. Various sand control methods have been proposed for tackling the sand production challenge, and research and experience have shown that the use of mechanical sand control methods are more suitable, with gravel packing being the most effective. Gravel packs are proven to be an effective mechanical sand control technique, and a good gravel pack completion design is of great importance to exclude sand from the wellbore while enhancing well productivity. Implementation of sand control by gravel packing in the Niger Delta is usually found to require importation of commercial gravel for the purpose of sand control which is a challenge in terms of high purchasing and transportation costs with import taxes. A solution is presented in this study which involves sourcing for gravel locally and investigating its suitability for sand control by gravel packing. Locally sourced gravel was compared with commercial gravel using sieve analysis and results showed that the locally sourced gravel closely met the requirements of the commercial gravel depicted by slot widths that are close to that obtained by the commercial gravel. Based on the results of this study, favorable performance is expected when locally sourced gravel is used for sand control by gravel packing in unconsolidated formations in the Niger Delta. It is recommended to source for different gravel types from different locations and evaluate using sieve analysis and Laser Particle Size Distribution Analysis to determine suitable gravel types for these type of formations.

Experimental and Numerical Analysis of Particle Migration and Patterning Behavior in a Gravel Pack

Due to its long lifespan and high sand-removal efficiency, gravel packing is one of the most applied sand control methods during the recovery of reservoirs with sanding problems. The blockage and retention of injected sand in a gravel pack is a complex process affected by multiple mechanisms. The majority of existing studies based on the phenomenological deep bed filtration (DBF) theory focused on the gravel pack’s overall permeability damage and failed to obtain the inner-pore particle distribution pattern. In this work, experiments and simulations were carried out to reveal the particle distribution in a gravel pack during flooding. In particular, through real-time monitoring of particle migration, the penetration depth and distribution pattern of invaded particles with different gravel-sand particle ratios, fluid viscosities and injection rates could be determined. By simplifying each unit bed element (UBE) into a pore-throat structure with four tunnels (two horizontals for discharge and two verticals for sedimentation), a new network simulation method, which combines deep bed filtration with a particle trajectory model, was implemented. Cross comparison of experimental and numerical results demonstrates the validity and accuracy of the model.

A novel apparatus for modeling the geological responses of reservoir and fluid-solid production behaviors during hydrate production.

Gas hydrate is a promising alternative energy resource that undergoes complex phase changes and coupled geological responses during hydrate production. Insufficient knowledge of those coupled behaviors still challenge safe and efficient gas production from hydrate. Here, a novel experimental apparatus was developed to simulate the gas-water-sand production and to evaluate the related multifield and multiphase processes. The experimental apparatus is equipped with displacement, ultrasonic, and electrical resistivity sensors and gas/water flowmeters, and this apparatus can work up to a maximum loading stress of 25 MPa and a maximum pore pressure of 20 MPa over a temperature range from -20 to 50 °C. The hydrate production and sand production case were performed on a synthetic specimen with hydrate saturation of 12.8% by using multi-step depressurization. The pressure-temperature conditions, settlement, ultrasonic propagation, electrical resistivity, and permeability of hydrate reservoirs during production were simultaneously monitored to evaluate the geological characteristics and heat and mass transfer characteristics of the hydrate reservoir. The results indicated that the gas/water production mainly occurred during the first third of each depressurization period, and their production rates were low at the beginning. Flowing water mobilized the sand particles, and the addition of gas exacerbated the sand-particle migration. Interpretation of the coupled behaviors supported that the reservoir could maintain a temporary stable structure even when losing a certain amount of sand particles with no sand control methods; however, necessary sand-prevention approaches are wise to support long-term reservoir production operations. These laboratory insights would contribute to optimizing the field strategies for economical gas production from hydrate.

Research on Erosion Wear of Slotted Screen Based on High Production Gas Field

Erosion wear is a common failure form of slotted screen in service. In this paper, based on CFD software and sand production data of a gas field in the Tarim Basin, the particle velocity and shear force at the slot of the flow field in the sieve tube were studied to determine the maximum area of erosion; at the same time, the velocity, viscosity, particle size and concentration of sand-carrying fluid were analyzed by orthogonal test, and the regression model of multi-factor maximum erosion rate was established. ① Through the analysis of the four factors on the degree of dependent variables, the order of the primary and secondary factors are: sand-carrying liquid flow rate, particle concentration, fluid viscosity, particle diameter, the effect of fluid viscosity and particle diameter on erosion rate is relatively small; ② According to the analysis of variance and range, the combination scheme of minimum erosion generation is obtained, and the calculation model of the erosion rate of the slotted screen is established. In order to reduce the erosion and abrasion in the actual oil and gas production process, the reasonable flow control and precise sand control method design and precision selection can be adopted; it provides a design basis for sand control and long-term effects of production in high-yield gas field.

A novel multi-path sand-control screen and its application in gravel packing of deepwater horizontal gas wells

Gravel packing is a promising sand control method for natural gas wells in deepwater environments. However, premature screenout, wellbore shrinkage, and packer installationlimit gravel packing efficiency in long-reach horizontal wells. In this paper, we introduce a novel multi-path screen that provides alternative pathways once the circulating annulus is blocked. The basic geometric parameters of the screen are given first. Then, the frictional pressure loss in each circulating unit during packing is evaluated. Finally, the application of this screen in a long-reach horizontal well in the northern South China Sea is discussed. The application results demonstrate the applicability of multi-path screens in complex downhole completion conditions. The multi-path screen described here may widen the application ranges of gravel packing techniques to meet the exploitation demand for unconventional natural gas resources, such as marine natural gas hydrate.

Simulation and application analysis of gravel packing in deepwater HT/HP wells

AbstractGravel packing is one of the main sand control methods for deep‐water high‐temperature and high‐pressure (HT/HP) reservoirs. According to the specific characteristics of deep‐water HT/HP and multichannel, considering the influence of slurry flowing through long‐distance multichannel and the slurry temperature alternation along the flow path, based on α–β wave packing theory, a coupling model of gravel packing in deep‐water HT/HP horizontal wells is established. The packing simulation algorithm and calculation process are designed to realize the gravel packing temperature pressure simulation and multistage refined friction calculation of deep‐water HT/HP horizontal wells. The influence of each packing parameter on the packing process is fully studied. Furthermore, the application simulation of the A10H well of the South China Sea deepwater HP well is carried out. The simulation results show that in the slurry injection stage and α wave packing stage, the packing pressure is low and the residual pressure window is large. In the β wave packing stage, the packing pressure increases rapidly, the residual pressure window shrinks rapidly, and finally, at the end of β wave packing, the residual pressure window becomes narrow. The viscosity of carrier fluid has a significant impact on the pressure window of packing operation. For the design pump rate of 5.6 bpm, the packing cannot be completed with 5.0 cp viscosity carrier fluid. For the carrier fluid with high viscosity, the multi‐β wave packing technique of pump reduction control pressure at the end of the β wave packing stage is used, and this process is simulated in this paper. Considering three constraints: not sand packed in the drilling string, without premature bridging in the α wave packing stage, and α and β wave packing pressure control conditions, the safe range of pump rate is determined under different operation safety margin conditions, which can provide technical support for on‐site operation.