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3 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
5 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
6 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
7 A New Fracturing Fluid with Temperature Resistance of 230℃
8 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
9 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
10 A Temperature Sensitive Expanding Microcapsule Anti-Gas-Channeling Cement Slurry
2 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
3 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
5 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
8 High Performance Water Base Drilling Fluid for Shale Gas Drilling
9 A New Fracturing Fluid with Temperature Resistance of 230℃
10 High Performance Water Base Drilling Fluid for Shale Gas Drilling
Articles in press have been peer-reviewed and accepted, which are not yet assigned to volumes /issues, but are citable by Digital Object Identifier (DOI).
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2025, 42(1): 1-19.
doi: 10.12358/j.issn.1001-5620.2025.01.001
Abstract:
To understand the new achievements of drilling fluid additives in China, this article reviews the recent development and application of drilling fluid additives, based on modified biomass materials, synthetic polymers, condensation reaction products, modified industrial by-products, and domestic waste modification products. Modified biomass materials, containing starch, cellulose, lignin, and humic acid, are mainly used for fluid loss reducers, and starch is the most common one; the most studied synthetic polymer materials are water-soluble polymers for fluid loss reducers, viscosity enhancers, encapsulating agents, and viscosity reducers. There are also some studies on water-insoluble materials used for plugging and fluid loss reducers. Monomers with good hydrolytic stability such as NVP as well as DMAM are used to enhance temperature-resistant, salt-resistant, and high valent ion-resistant ability. Condensation reaction products focus on emulsifiers and viscosity enhancers of oil-based drilling fluid, and esterification and amidation reaction of lubricants in water-based drilling fluid as well. Some research has also been conducted on the preparation of drilling fluid treatment agents using industrial by-products and household waste. Although there has already been a large number of research on drilling fluid additives, the research is still not innovative, in-depth, and comprehensive enough. Due to the limitations of molecular design, synthetic means, and evaluation methods, there are relatively few drilling fluid additives that can meet the needs of complex fields on site.There is still a phenomenon of similar or low-level repetitive research. Combining with practice. The research on treatment agents should aim to break through traditional thinking and mechanisms. Around the goals of simplifying drilling fluid components, reducing drilling fluid costs, improving drilling fluid functions, enhancing drilling fluid quality, and promoting green development. Strengthen the development and utilization of biomass resources, innovate synthesis methods and processes, and develop low-cost, high-quality, and long-term multifunctional materials with good comprehensive performance.
To understand the new achievements of drilling fluid additives in China, this article reviews the recent development and application of drilling fluid additives, based on modified biomass materials, synthetic polymers, condensation reaction products, modified industrial by-products, and domestic waste modification products. Modified biomass materials, containing starch, cellulose, lignin, and humic acid, are mainly used for fluid loss reducers, and starch is the most common one; the most studied synthetic polymer materials are water-soluble polymers for fluid loss reducers, viscosity enhancers, encapsulating agents, and viscosity reducers. There are also some studies on water-insoluble materials used for plugging and fluid loss reducers. Monomers with good hydrolytic stability such as NVP as well as DMAM are used to enhance temperature-resistant, salt-resistant, and high valent ion-resistant ability. Condensation reaction products focus on emulsifiers and viscosity enhancers of oil-based drilling fluid, and esterification and amidation reaction of lubricants in water-based drilling fluid as well. Some research has also been conducted on the preparation of drilling fluid treatment agents using industrial by-products and household waste. Although there has already been a large number of research on drilling fluid additives, the research is still not innovative, in-depth, and comprehensive enough. Due to the limitations of molecular design, synthetic means, and evaluation methods, there are relatively few drilling fluid additives that can meet the needs of complex fields on site.There is still a phenomenon of similar or low-level repetitive research. Combining with practice. The research on treatment agents should aim to break through traditional thinking and mechanisms. Around the goals of simplifying drilling fluid components, reducing drilling fluid costs, improving drilling fluid functions, enhancing drilling fluid quality, and promoting green development. Strengthen the development and utilization of biomass resources, innovate synthesis methods and processes, and develop low-cost, high-quality, and long-term multifunctional materials with good comprehensive performance.
2025, 42(1): 20-29.
doi: 10.12358/j.issn.1001-5620.2025.01.002
Abstract:
Celluloses are a common additive used in various water-based drilling fluids to effectively reduce the filtration rate, enhance the drilled solids suspending capacity and improve the rheology of the drilling fluids. Nanocellulose as an innovative drilling fluid additive has, apart from the advantages of the common cellulose, new properties such as high temperature stability and resistance to salt and alkali contamination. The nanocellulose also remarkably improve the stability and rheology, and effectively reduce the filtration rate of the drilling fluids. This paper introduces the methods presently used to produce nanocellulose and the application of nanocellulose in drilling fluids. Prospects are made in the paper of the application of the nanocellulose in drilling fluids, aiming at providing a reference for producing new environmentally-friendly high temperature drilling fluid additives.
Celluloses are a common additive used in various water-based drilling fluids to effectively reduce the filtration rate, enhance the drilled solids suspending capacity and improve the rheology of the drilling fluids. Nanocellulose as an innovative drilling fluid additive has, apart from the advantages of the common cellulose, new properties such as high temperature stability and resistance to salt and alkali contamination. The nanocellulose also remarkably improve the stability and rheology, and effectively reduce the filtration rate of the drilling fluids. This paper introduces the methods presently used to produce nanocellulose and the application of nanocellulose in drilling fluids. Prospects are made in the paper of the application of the nanocellulose in drilling fluids, aiming at providing a reference for producing new environmentally-friendly high temperature drilling fluid additives.
2025, 42(1): 30-40.
doi: 10.12358/j.issn.1001-5620.2025.01.003
Abstract:
The shale gas formations in the marine-continental transitional facies of the eastern margin of the Ordos Basin are tight gas formations with complex pore and fracture structures as well as high heterogeneity which result in special stress sensitivity of the formations. To understand the degree of the stress sensitivity of the reservoirs, stress sensitivity experiments were performed on cores taken from the marine-continental transitional facies of the eastern margin of the Ordos Basin. The experimental results, combined with the understanding of the lithology and the physical properties of the reservoirs, help reveal the mechanisms of stress sensitivity of the shale gas reservoirs concerned. The studies performed indicate that when the effective stress is increased from 3 MPa to 35 MPa, the permeability of the artificial fractures, the natural fractures and the base core decreases by 97.1%, 86.8% and 50,5%, respectively. During unloading of the effective stress, the permeability of the artificial fractures, the natural fractures and the base core is recovered by 21.4%, 19.0% and 11.6%, respectively, showing significant stress sensitivity hysteresis effects. The stress sensitivity coefficients of the artificial fractures, the natural fractures and the base core are 0.65, 0.58 and 0.19, respectively, and the degrees of stress sensitivity corresponding to these stress sensitivity coefficients are classified as strong-moderate to strong, strong-moderate to weak and weak. The stress sensitivity coefficients show that the multi-scale pore-fracture structure of the shales under research have significant stress sensitivity. The main control factors of formation damage by stress sensitivity include the mineral components, the development of the fractures as well as the pore structure of the shales in the marine-continental transitional facies. It is thus suggested that a reservoir-protective gas production system be developed, and the production of gas be controlled to ensure high production rate and stable production of the gas wells drilled in the marine-continental transitional facies of the eastern margin of the Ordos Basin.
The shale gas formations in the marine-continental transitional facies of the eastern margin of the Ordos Basin are tight gas formations with complex pore and fracture structures as well as high heterogeneity which result in special stress sensitivity of the formations. To understand the degree of the stress sensitivity of the reservoirs, stress sensitivity experiments were performed on cores taken from the marine-continental transitional facies of the eastern margin of the Ordos Basin. The experimental results, combined with the understanding of the lithology and the physical properties of the reservoirs, help reveal the mechanisms of stress sensitivity of the shale gas reservoirs concerned. The studies performed indicate that when the effective stress is increased from 3 MPa to 35 MPa, the permeability of the artificial fractures, the natural fractures and the base core decreases by 97.1%, 86.8% and 50,5%, respectively. During unloading of the effective stress, the permeability of the artificial fractures, the natural fractures and the base core is recovered by 21.4%, 19.0% and 11.6%, respectively, showing significant stress sensitivity hysteresis effects. The stress sensitivity coefficients of the artificial fractures, the natural fractures and the base core are 0.65, 0.58 and 0.19, respectively, and the degrees of stress sensitivity corresponding to these stress sensitivity coefficients are classified as strong-moderate to strong, strong-moderate to weak and weak. The stress sensitivity coefficients show that the multi-scale pore-fracture structure of the shales under research have significant stress sensitivity. The main control factors of formation damage by stress sensitivity include the mineral components, the development of the fractures as well as the pore structure of the shales in the marine-continental transitional facies. It is thus suggested that a reservoir-protective gas production system be developed, and the production of gas be controlled to ensure high production rate and stable production of the gas wells drilled in the marine-continental transitional facies of the eastern margin of the Ordos Basin.
2025, 42(1): 41-50.
doi: 10.12358/j.issn.1001-5620.2025.01.004
Abstract:
Mud losses into fractures is one of the most difficult problems encountered in drilling unstable formations. Particle bridging is the most effective method of controlling mud losses into fractures. In traditional fracture experimental apparatus how the plugging layers are formed inside the fractures by the flow of particles is still not clearly understood, and this restricts the scientific build-up of a lost circulation slurry. To investigate the characteristic behavior of particles and the dynamic evolution of plugging layers inside fractures, a wellbore-fracture visualization experimental device is set up, and is used to systematically study the behavioral characteristics of the particles, the pattern in which the plugging layers are formed as well as the influencing mechanisms of the formation of the plugging layers under the effects of key factors such as particle size, particle concentration, flowrate of the particle slurry pumped into the fractures and the viscosity of the carrying fluid etc. The experimental results show that the plugging process taking place inside the fractures can be divided into four stages in each of which co-exist the mixing of the particles and the change of the characteristic behavior of the particles. The position at which a plugging layer is set up is highly sensitive to the size distribution of the particles, the concentration of the particles affects the time required for the fractures to be plugged, the structure of the plugging layers is easily altered by the viscosity of the carrying fluid, and too high a pump rate may damage the plugging structure previously formed.
Mud losses into fractures is one of the most difficult problems encountered in drilling unstable formations. Particle bridging is the most effective method of controlling mud losses into fractures. In traditional fracture experimental apparatus how the plugging layers are formed inside the fractures by the flow of particles is still not clearly understood, and this restricts the scientific build-up of a lost circulation slurry. To investigate the characteristic behavior of particles and the dynamic evolution of plugging layers inside fractures, a wellbore-fracture visualization experimental device is set up, and is used to systematically study the behavioral characteristics of the particles, the pattern in which the plugging layers are formed as well as the influencing mechanisms of the formation of the plugging layers under the effects of key factors such as particle size, particle concentration, flowrate of the particle slurry pumped into the fractures and the viscosity of the carrying fluid etc. The experimental results show that the plugging process taking place inside the fractures can be divided into four stages in each of which co-exist the mixing of the particles and the change of the characteristic behavior of the particles. The position at which a plugging layer is set up is highly sensitive to the size distribution of the particles, the concentration of the particles affects the time required for the fractures to be plugged, the structure of the plugging layers is easily altered by the viscosity of the carrying fluid, and too high a pump rate may damage the plugging structure previously formed.
2025, 42(1): 51-57.
doi: 10.12358/j.issn.1001-5620.2025.01.005
Abstract:
Based on the geological analysis of the carbonate rock formation in Shunbei oil and gas field, the reasons for the formation's easy wellbore instability are clarified: first, the rock is easy to be broken and the fracture develops, which is easy to have secondary fracture development, malignant leakage and even well collapse; Second, the bottom hole temperature is high, and the drilling fluid treatment agent is easy to fail at high temperature; Third, the plugging capacity of the currently used polysulfonate drilling fluid is insufficient, which can’t effectively plug formation cracks and reduce pressure transfer; Fourth, the cementation ability of the current drilling fluid is insufficient, which can’t effectively improve the compressive strength of the near-wellbore rock. To solve the above difficulties, a high temperature resistant cementing sealer AD-1 was synthesized from acrylamide, dimethyldiallyl ammonium chloride, 2-acrylamide-2-methylpropanesulfonate sodium and dopamine hydrochloride. The cementation and plugging properties of the cementing agent were evaluated. The experimental results show that the axial compressive strength of the cemented dry carbonate sand beds is up to 2.5-5.0 MPa at 180℃, and the compressive strength is increased by more than 4 times. The compressive strength of the unconsolidated wet sand beds is 0 MPa, and the compressive strength of the consolidated wet carbonate sand beds is increased to 0.2-0.5 MPa. After adding the cementing sealer, the plugging ability of the polysulfonate drilling fluid was significantly improved, and the drilling fluid could effectively plug the sand beds composed of 40-60 and 60-80 mesh carbonate debris, with the maximum pressure ≥6 MPa, and the cumulative loss in 30 minutes was about 10 mL. In addition, the viscosity of the drilling fluid will increase dramatically when the additive amount exceeds 1.0%, and the additive amount should be controlled as appropriate. Therefore, the polysulfonate drilling fluid system with AD-1 as the core has good temperature resistance, cementation and plugging properties, which can provide strong technical support for borehole stability technology in Shunbei region.
Based on the geological analysis of the carbonate rock formation in Shunbei oil and gas field, the reasons for the formation's easy wellbore instability are clarified: first, the rock is easy to be broken and the fracture develops, which is easy to have secondary fracture development, malignant leakage and even well collapse; Second, the bottom hole temperature is high, and the drilling fluid treatment agent is easy to fail at high temperature; Third, the plugging capacity of the currently used polysulfonate drilling fluid is insufficient, which can’t effectively plug formation cracks and reduce pressure transfer; Fourth, the cementation ability of the current drilling fluid is insufficient, which can’t effectively improve the compressive strength of the near-wellbore rock. To solve the above difficulties, a high temperature resistant cementing sealer AD-1 was synthesized from acrylamide, dimethyldiallyl ammonium chloride, 2-acrylamide-2-methylpropanesulfonate sodium and dopamine hydrochloride. The cementation and plugging properties of the cementing agent were evaluated. The experimental results show that the axial compressive strength of the cemented dry carbonate sand beds is up to 2.5-5.0 MPa at 180℃, and the compressive strength is increased by more than 4 times. The compressive strength of the unconsolidated wet sand beds is 0 MPa, and the compressive strength of the consolidated wet carbonate sand beds is increased to 0.2-0.5 MPa. After adding the cementing sealer, the plugging ability of the polysulfonate drilling fluid was significantly improved, and the drilling fluid could effectively plug the sand beds composed of 40-60 and 60-80 mesh carbonate debris, with the maximum pressure ≥6 MPa, and the cumulative loss in 30 minutes was about 10 mL. In addition, the viscosity of the drilling fluid will increase dramatically when the additive amount exceeds 1.0%, and the additive amount should be controlled as appropriate. Therefore, the polysulfonate drilling fluid system with AD-1 as the core has good temperature resistance, cementation and plugging properties, which can provide strong technical support for borehole stability technology in Shunbei region.
2025, 42(1): 58-65.
doi: 10.12358/j.issn.1001-5620.2025.01.006
Abstract:
Well drilling in the central part of the block Jinzhou-25-1 in Bohai basin has frequently encountered borehole wall destabilization when drilling the Dongying formation shales. Based on the analyses of the components and structure of the shales as well as the measurement of their mechanical properties, it was found that the borehole wall destabilizes mainly in two mechanisms, first is the weakening of the shales caused by hydration and swelling, second is the shearing slip of the formations along the bedding planes. Based on this understanding, a water based drilling fluid PEM and a synthetic based drilling fluid BIODRILL S were compared for their performance from several aspects such as basic properties, plugging capacity, inhibitive capacity and the ability to maintain mechanical strength of a formation etc. It was found that the BIODRILL S drilling fluid has several advantages over the PEM drilling fluid, such as high percentage of shale cuttings recovery in hot rolling test, lower linear expansion rate, lower high temperature high pressure filtration rate as well as better performance in maintaining the mechanical strength of the shale formations. A nano-latex plugging agent PF-NSEAL was added into the BIODRILL S drilling fluid at concentrations between 2% and 2.5%, rendering it better microfracture plugging performance. In field operation, the optimized BIODRILL S drilling fluid was used to drill two extended reach wells, the number of downhole problems was greatly reduced, and the drilling rate was increased by 43.7%. The use of the optimized BIODRILL S synthetic based drilling fluid has provided a technical support for solving the borehole wall destabilization problem encountered in block Jinzhou-25-1.
Well drilling in the central part of the block Jinzhou-25-1 in Bohai basin has frequently encountered borehole wall destabilization when drilling the Dongying formation shales. Based on the analyses of the components and structure of the shales as well as the measurement of their mechanical properties, it was found that the borehole wall destabilizes mainly in two mechanisms, first is the weakening of the shales caused by hydration and swelling, second is the shearing slip of the formations along the bedding planes. Based on this understanding, a water based drilling fluid PEM and a synthetic based drilling fluid BIODRILL S were compared for their performance from several aspects such as basic properties, plugging capacity, inhibitive capacity and the ability to maintain mechanical strength of a formation etc. It was found that the BIODRILL S drilling fluid has several advantages over the PEM drilling fluid, such as high percentage of shale cuttings recovery in hot rolling test, lower linear expansion rate, lower high temperature high pressure filtration rate as well as better performance in maintaining the mechanical strength of the shale formations. A nano-latex plugging agent PF-NSEAL was added into the BIODRILL S drilling fluid at concentrations between 2% and 2.5%, rendering it better microfracture plugging performance. In field operation, the optimized BIODRILL S drilling fluid was used to drill two extended reach wells, the number of downhole problems was greatly reduced, and the drilling rate was increased by 43.7%. The use of the optimized BIODRILL S synthetic based drilling fluid has provided a technical support for solving the borehole wall destabilization problem encountered in block Jinzhou-25-1.
2025, 42(1): 66-73.
doi: 10.12358/j.issn.1001-5620.2025.01.007
Abstract:
The effect of reservoir lithology on the stability of the wellbore in Xinjiang Shapai Group 9 was investigated from multiple perspectives via X-ray diffraction, infrared spectroscopy, scanning electron microscopy, and water contact angle. The inhibition performance, inhibition mechanism, and application of three typical ionic liquids (MOA, CP-DES, MM6) were evaluated.The rocks in this group have a high content of clay minerals and contain a large number of hydroxyl groups on their surfaces, which are highly susceptible to swelling with water. Among the samples treated by three ionic liquid inhibitors, the lowest linear swelling rate (21.2%), the highest hot-rolling recovery (63.1%, 180℃), and the excellent application results of drilling fluid system indicate that deep eutectic solvent ionic liquid (CP-DES) is the most suitable inhibitor for the Xinjiang Shapai Group 9.Further studies revealed that CP-DES could form strong interactions with the clay surface through hydrogen bonding and enter the clay interlayer to hinder the intrusion of water. Meanwhile, the cationic groups could compress the electric double layer on the clay surfaces and weaken the electrostatic repulsion between the particles, which consequently inhibited the hydration swelling of the clay.
The effect of reservoir lithology on the stability of the wellbore in Xinjiang Shapai Group 9 was investigated from multiple perspectives via X-ray diffraction, infrared spectroscopy, scanning electron microscopy, and water contact angle. The inhibition performance, inhibition mechanism, and application of three typical ionic liquids (MOA, CP-DES, MM6) were evaluated.The rocks in this group have a high content of clay minerals and contain a large number of hydroxyl groups on their surfaces, which are highly susceptible to swelling with water. Among the samples treated by three ionic liquid inhibitors, the lowest linear swelling rate (21.2%), the highest hot-rolling recovery (63.1%, 180℃), and the excellent application results of drilling fluid system indicate that deep eutectic solvent ionic liquid (CP-DES) is the most suitable inhibitor for the Xinjiang Shapai Group 9.Further studies revealed that CP-DES could form strong interactions with the clay surface through hydrogen bonding and enter the clay interlayer to hinder the intrusion of water. Meanwhile, the cationic groups could compress the electric double layer on the clay surfaces and weaken the electrostatic repulsion between the particles, which consequently inhibited the hydration swelling of the clay.
2025, 42(1): 74-81.
doi: 10.12358/j.issn.1001-5620.2025.01.008
Abstract:
Biodegradable polyester temporary plugging agents (TPAs) have good degradability and low damage to reservoirs, but the disadvantages, which include low thermal stability, low strength of the plugging layers formed and high production cost etc., make it difficult for them to be widely used. To satisfy the requirements for TPAs to work at elevated temperatures, a new biodegradable TPA is developed. This new TPA is prepared by melt blending polybutylene terephthalate (PBT), which has slower hydrolysis rate, and polyamide 6 (PA6), and an epoxy chain extender ADR is added to improve the compatibility of the melt blending materials. The new TPA has better thermal stability and forms plugging layers of higher strength. Experimental results show that the new TPA has better degradability, in a NaOH solution (pH=10) at 120-150℃, percent weight loss of the new TPA after 20-60 d is greater than 80%. When the ratio of PBT and PA6 in the melt blending system is 70% PBT/30% PA6, and into the melt blending system add 1.5% ADR, the compressive strength of the new TPA can be 91 MPa, after degrading at 150℃ for 16 h the compressive strength is still greater than 70 MPa. This new TPA has good compatibility with drilling fluids and excellent plugging performance, and after degrading at 120℃ for 14 d, the residual compressive strength of the plugging layer is 2 MPa.
Biodegradable polyester temporary plugging agents (TPAs) have good degradability and low damage to reservoirs, but the disadvantages, which include low thermal stability, low strength of the plugging layers formed and high production cost etc., make it difficult for them to be widely used. To satisfy the requirements for TPAs to work at elevated temperatures, a new biodegradable TPA is developed. This new TPA is prepared by melt blending polybutylene terephthalate (PBT), which has slower hydrolysis rate, and polyamide 6 (PA6), and an epoxy chain extender ADR is added to improve the compatibility of the melt blending materials. The new TPA has better thermal stability and forms plugging layers of higher strength. Experimental results show that the new TPA has better degradability, in a NaOH solution (pH=10) at 120-150℃, percent weight loss of the new TPA after 20-60 d is greater than 80%. When the ratio of PBT and PA6 in the melt blending system is 70% PBT/30% PA6, and into the melt blending system add 1.5% ADR, the compressive strength of the new TPA can be 91 MPa, after degrading at 150℃ for 16 h the compressive strength is still greater than 70 MPa. This new TPA has good compatibility with drilling fluids and excellent plugging performance, and after degrading at 120℃ for 14 d, the residual compressive strength of the plugging layer is 2 MPa.
2025, 42(1): 82-89.
doi: 10.12358/j.issn.1001-5620.2025.01.009
Abstract:
The mid-upper Early Miocene Murree formation in the ADHI block, northern Pakistan, is a long red mudstone located in the Φ311.15 mm interval with a length of 1400-1600 m, which is a major difficulty and extremely challenging drilling operation in the block. The red mudstone section has the characteristics of strong dispersion and high slurry production, and the rheological property of drilling fluid is often out of control. Easy to expand and shrink, bit balling, return a large ball of cuttings, blocking the horn; The formation pressure coefficient is high, the density is as high as 1.80-2.00 g/cm3, and the accidents such as differential pressure sticking and broken drilling tools often occur. Formation water, high pressure and low permeability, 1-3 m3/h; The high density further increases the difficulty of controlling rheology and poor solid content of drilling fluid. In order to solve the above Drilling problems in the AHDI block, show Chuanqing's image as a pioneer in complex oil and gas drilling in the open oil and gas service market overseas, and establish the brand of "CCDC Drilling Fluid", the author conducted analysis and research on the mineral components and hydration characteristics of mudstone in the Murree formation. A high-density high-performance water-based drilling fluid system with a density of 2.20 g/cm3, yield point less than 20 Pa, temperature resistance of 100℃ and resistance to 5% mudstone pollution suitable for ADHI block in northern Pakistan was developed based on "efficient mudstone inhibitor, clay accretion inhibitor and ROP Enhancer, nano-microne plugging agent and application technology of macromolecule encapsulation inhibitor under high density conditions". Successfully applied 4 Wells in Pakistan.
The mid-upper Early Miocene Murree formation in the ADHI block, northern Pakistan, is a long red mudstone located in the Φ311.15 mm interval with a length of 1400-1600 m, which is a major difficulty and extremely challenging drilling operation in the block. The red mudstone section has the characteristics of strong dispersion and high slurry production, and the rheological property of drilling fluid is often out of control. Easy to expand and shrink, bit balling, return a large ball of cuttings, blocking the horn; The formation pressure coefficient is high, the density is as high as 1.80-2.00 g/cm3, and the accidents such as differential pressure sticking and broken drilling tools often occur. Formation water, high pressure and low permeability, 1-3 m3/h; The high density further increases the difficulty of controlling rheology and poor solid content of drilling fluid. In order to solve the above Drilling problems in the AHDI block, show Chuanqing's image as a pioneer in complex oil and gas drilling in the open oil and gas service market overseas, and establish the brand of "CCDC Drilling Fluid", the author conducted analysis and research on the mineral components and hydration characteristics of mudstone in the Murree formation. A high-density high-performance water-based drilling fluid system with a density of 2.20 g/cm3, yield point less than 20 Pa, temperature resistance of 100℃ and resistance to 5% mudstone pollution suitable for ADHI block in northern Pakistan was developed based on "efficient mudstone inhibitor, clay accretion inhibitor and ROP Enhancer, nano-microne plugging agent and application technology of macromolecule encapsulation inhibitor under high density conditions". Successfully applied 4 Wells in Pakistan.
2025, 42(1): 90-101.
doi: 10.12358/j.issn.1001-5620.2025.01.010
Abstract:
Accurate prediction of the thermodynamic stability of gas hydrates in salt-bearing systems is of great significance for predicting the accumulation range and determining the decomposition domain of hydrate. Therefore, considering the non-spherical characteristics of hydrate crystal cavity and the electrolyte interaction in the salt-containing system, a thermodynamic model of gas hydrate phase equilibrium considering salt concentration was established, and compared with the experimental data. The results show that the established three-dimensional phase equilibrium surface can effectively predict the thermodynamic stability of NGH, and the absolute mean relative deviation of temperature is only 0.08 in pure water, and no more than 0.15 in salt. When the molar fraction of chloride is greater than 0.02 and the pressure is higher than 20 MPa, the chemical factors cause the p-T curve to shift. When the pressure is small, the equilibrium temperature changes dramatically along the gradient of salt concentration, and the p-T curve no longer has translation characteristics. At the same time, AlCl3 has stronger inhibitory effect on CH4 hydrate than other chlorine salts when the molar fraction is the same. The lnp-X-1/T three-dimensional surface of CH4 hydrate exhibits better Clausius-Clapeyron linear behavior locally, and the surface as a whole has certain nonlinear characteristics. Moreover, the better the inhibition effect of chloride electrolyte on CH4 hydrate, the stronger the nonlinear characteristics.
Accurate prediction of the thermodynamic stability of gas hydrates in salt-bearing systems is of great significance for predicting the accumulation range and determining the decomposition domain of hydrate. Therefore, considering the non-spherical characteristics of hydrate crystal cavity and the electrolyte interaction in the salt-containing system, a thermodynamic model of gas hydrate phase equilibrium considering salt concentration was established, and compared with the experimental data. The results show that the established three-dimensional phase equilibrium surface can effectively predict the thermodynamic stability of NGH, and the absolute mean relative deviation of temperature is only 0.08 in pure water, and no more than 0.15 in salt. When the molar fraction of chloride is greater than 0.02 and the pressure is higher than 20 MPa, the chemical factors cause the p-T curve to shift. When the pressure is small, the equilibrium temperature changes dramatically along the gradient of salt concentration, and the p-T curve no longer has translation characteristics. At the same time, AlCl3 has stronger inhibitory effect on CH4 hydrate than other chlorine salts when the molar fraction is the same. The lnp-X-1/T three-dimensional surface of CH4 hydrate exhibits better Clausius-Clapeyron linear behavior locally, and the surface as a whole has certain nonlinear characteristics. Moreover, the better the inhibition effect of chloride electrolyte on CH4 hydrate, the stronger the nonlinear characteristics.
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
摘要：
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
2016, 33(5): 1-8.
doi: 10.3969/j.issn.1001-5620.2016.05.001
摘要：
综述了国内外页岩气井井壁失稳机理、稳定井壁主要方法及水基钻井液技术研究与应用现状，讨论了当前中国页岩气井钻井液技术面临的主要技术难题，分析了美国页岩气井与中国主要页岩气产区井壁失稳机理的差异，指出了中国页岩气井水基钻井液技术研究存在的误区与不足，提出了中国页岩气井水基钻井液技术发展方向。
综述了国内外页岩气井井壁失稳机理、稳定井壁主要方法及水基钻井液技术研究与应用现状，讨论了当前中国页岩气井钻井液技术面临的主要技术难题，分析了美国页岩气井与中国主要页岩气产区井壁失稳机理的差异，指出了中国页岩气井水基钻井液技术研究存在的误区与不足，提出了中国页岩气井水基钻井液技术发展方向。
2016, 33(1): 33-36.
doi: 10.3969/j.issn.1001-5620.2016.01.007
摘要：
页岩具有极低的渗透率和极小的孔喉尺寸,传统封堵剂难以在页岩表面形成有效的泥饼,只有纳米级颗粒才能封堵页岩的孔喉,阻止液相侵入地层,维持井壁稳定,保护储层。以苯乙烯(St)、甲基丙烯酸甲酯(MMA)为单体,过硫酸钾(KPS)为引发剂,采用乳液聚合法制备了纳米聚合物微球封堵剂SD-seal。通过红外光谱、透射电镜、热重分析和激光粒度分析对产物进行了表征,通过龙马溪组岩样的压力传递实验研究了其封堵性能。结果表明,SD-seal纳米粒子分散性好,形状规则(基本为球形),粒度较均匀(20 nm左右),分解温度高达402.5℃,热稳定性好,阻缓压力传递效果显著,使龙马溪组页岩岩心渗透率降低95%。
页岩具有极低的渗透率和极小的孔喉尺寸,传统封堵剂难以在页岩表面形成有效的泥饼,只有纳米级颗粒才能封堵页岩的孔喉,阻止液相侵入地层,维持井壁稳定,保护储层。以苯乙烯(St)、甲基丙烯酸甲酯(MMA)为单体,过硫酸钾(KPS)为引发剂,采用乳液聚合法制备了纳米聚合物微球封堵剂SD-seal。通过红外光谱、透射电镜、热重分析和激光粒度分析对产物进行了表征,通过龙马溪组岩样的压力传递实验研究了其封堵性能。结果表明,SD-seal纳米粒子分散性好,形状规则(基本为球形),粒度较均匀(20 nm左右),分解温度高达402.5℃,热稳定性好,阻缓压力传递效果显著,使龙马溪组页岩岩心渗透率降低95%。
2018, 35(2): 1-16.
doi: 10.3969/j.issn.1001-5620.2018.02.001
摘要：
通常在勘探开发油气过程中会发生不同程度的油气层损害，导致产量下降、甚至"枪毙"油气层等，钻井液是第一个与油气层相接触的外来流体，引起的油气层损害程度往往较大。为减轻或避免钻井液导致的油气层损害、提高单井产量，国内外学者们进行了长达半个世纪以上的研究工作，先后建立了"屏蔽暂堵、精细暂堵、物理化学膜暂堵"三代暂堵型保护油气层钻井液技术，使保护油气层效果逐步提高，经济效益明显。但是，与石油工程师们追求的"超低"损害目标仍存在一定差距，特别是随着非常规、复杂、超深层、超深水等类型油气层勘探开发力度的加大，以前的保护技术难以满足要求。为此，将仿生学引入保护油气层钻井液理论中，发展了适合不同油气层渗透率大小的"超双疏、生物膜、协同增效"仿生技术，并在各大油田得到推广应用，达到了"超低"损害目标，标志着第四代暂堵型保护油气层钻井液技术的建立。对上述4代暂堵型保护油气层技术的理论基础、实施方案、室内评价、现场应用效果与优缺点等进行了论述，并通过梳理阐明了将来的研究方向与发展趋势，对现场技术人员和科技工作者具有较大指导意义。
通常在勘探开发油气过程中会发生不同程度的油气层损害，导致产量下降、甚至"枪毙"油气层等，钻井液是第一个与油气层相接触的外来流体，引起的油气层损害程度往往较大。为减轻或避免钻井液导致的油气层损害、提高单井产量，国内外学者们进行了长达半个世纪以上的研究工作，先后建立了"屏蔽暂堵、精细暂堵、物理化学膜暂堵"三代暂堵型保护油气层钻井液技术，使保护油气层效果逐步提高，经济效益明显。但是，与石油工程师们追求的"超低"损害目标仍存在一定差距，特别是随着非常规、复杂、超深层、超深水等类型油气层勘探开发力度的加大，以前的保护技术难以满足要求。为此，将仿生学引入保护油气层钻井液理论中，发展了适合不同油气层渗透率大小的"超双疏、生物膜、协同增效"仿生技术，并在各大油田得到推广应用，达到了"超低"损害目标，标志着第四代暂堵型保护油气层钻井液技术的建立。对上述4代暂堵型保护油气层技术的理论基础、实施方案、室内评价、现场应用效果与优缺点等进行了论述，并通过梳理阐明了将来的研究方向与发展趋势，对现场技术人员和科技工作者具有较大指导意义。
2016, 33(4): 74-78.
doi: 10.3969/j.issn.1001-5620.2016.04.015
摘要：
利用自主研发的水泥环密封性实验装置研究了套管内加卸压循环作用下水泥环的密封性，根据实验结果得出了循环应力作用下水泥环密封性失效的机理。实验结果显示，在较低套管内压循环作用下，水泥环保持密封性所能承受的应力循环次数较多；在较高循环应力作用下，水泥环密封性失效时循环次数较少。表明在套管内较低压力作用下，水泥环所受的应力较低，应力水平处于弹性状态，在加卸载的循环作用下，水泥环可随之弹性变形和弹性恢复；在较高应力作用下，水泥环内部固有的微裂纹和缺陷逐渐扩展和连通，除了发生弹性变形还产生了塑性变形；随着应力循环次数的增加，塑性变形也不断地累积。循环压力卸载时，套管弹性回缩而水泥环塑性变形不可完全恢复，2者在界面处的变形不协调而引起拉应力。当拉应力超过界面处的胶结强度时出现微环隙，导致水泥环密封性失效，水泥环发生循环应力作用的低周期密封性疲劳破坏。套管内压力越大，水泥环中产生的应力水平越高，产生的塑性变形越大，每次卸载时产生的残余应变和界面处拉应力也越大，因此引起密封性失效的应力循环次数越少。
利用自主研发的水泥环密封性实验装置研究了套管内加卸压循环作用下水泥环的密封性，根据实验结果得出了循环应力作用下水泥环密封性失效的机理。实验结果显示，在较低套管内压循环作用下，水泥环保持密封性所能承受的应力循环次数较多；在较高循环应力作用下，水泥环密封性失效时循环次数较少。表明在套管内较低压力作用下，水泥环所受的应力较低，应力水平处于弹性状态，在加卸载的循环作用下，水泥环可随之弹性变形和弹性恢复；在较高应力作用下，水泥环内部固有的微裂纹和缺陷逐渐扩展和连通，除了发生弹性变形还产生了塑性变形；随着应力循环次数的增加，塑性变形也不断地累积。循环压力卸载时，套管弹性回缩而水泥环塑性变形不可完全恢复，2者在界面处的变形不协调而引起拉应力。当拉应力超过界面处的胶结强度时出现微环隙，导致水泥环密封性失效，水泥环发生循环应力作用的低周期密封性疲劳破坏。套管内压力越大，水泥环中产生的应力水平越高，产生的塑性变形越大，每次卸载时产生的残余应变和界面处拉应力也越大，因此引起密封性失效的应力循环次数越少。
2017, 34(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2017.01.001
摘要：
分析了硬脆性泥页岩井壁失稳的原因，介绍了纳米材料特点及其应用，并概述了国内外钻井液用纳米封堵剂的研究进展，包括有机纳米封堵剂、无机纳米封堵剂、有机/无机纳米封堵剂，以及纳米封堵剂现场应用案例。笔者认为：利用无机纳米材料刚性特征以及有机聚合物可任意变形、支化成膜等特性，形成的一种核壳结构的无机/聚合物类纳米封堵剂，能够很好地分散到钻井液中，且对钻井液黏度和切力影响较小，这种类型的纳米封堵剂能够在低浓度下封堵泥页岩孔喉，建立一种疏水型且具有一定强度的泥页岩人工井壁，这不仅能够阻止钻井液侵入，而且还能提高地层承压能力，无机纳米材料与有机聚合物的结合是未来钻井液防塌剂的发展方向。
分析了硬脆性泥页岩井壁失稳的原因，介绍了纳米材料特点及其应用，并概述了国内外钻井液用纳米封堵剂的研究进展，包括有机纳米封堵剂、无机纳米封堵剂、有机/无机纳米封堵剂，以及纳米封堵剂现场应用案例。笔者认为：利用无机纳米材料刚性特征以及有机聚合物可任意变形、支化成膜等特性，形成的一种核壳结构的无机/聚合物类纳米封堵剂，能够很好地分散到钻井液中，且对钻井液黏度和切力影响较小，这种类型的纳米封堵剂能够在低浓度下封堵泥页岩孔喉，建立一种疏水型且具有一定强度的泥页岩人工井壁，这不仅能够阻止钻井液侵入，而且还能提高地层承压能力，无机纳米材料与有机聚合物的结合是未来钻井液防塌剂的发展方向。
2016, 33(6): 121-126.
doi: 10.3969/j.issn.1001-5620.2016.06.022
摘要：
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现，存地液量越大，一年累积产量越高，与常规的返排率越高产量越高概念恰恰相反，可能与存地液的自发渗吸替油有关。核磁实验结果表明，渗吸替油不同于驱替作用，渗吸过程中小孔隙对采出程度贡献大，而驱替过程中大孔隙对采出程度贡献大，但从现场致密储层岩心孔隙度来看，储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素，探索影响压裂液油水置换的关键影响因素，得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明，各参数对渗吸速度的影响顺序为：界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大，渗吸采收率越大，但是增幅逐渐减小；原油黏度越小，渗吸采收率越大；渗吸液矿化度越大，渗吸采收率越大；当渗吸液中助排剂浓度在0.005%~5%，即界面张力在0.316~10.815 mN/m范围内时，浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明：并不是界面张力越低，采收率越高，而是存在某一最佳界面张力，使地层中被绕流油的数量减少，渗吸采收率达到最高，为油田提高致密储层采收率提供实验指导。
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现，存地液量越大，一年累积产量越高，与常规的返排率越高产量越高概念恰恰相反，可能与存地液的自发渗吸替油有关。核磁实验结果表明，渗吸替油不同于驱替作用，渗吸过程中小孔隙对采出程度贡献大，而驱替过程中大孔隙对采出程度贡献大，但从现场致密储层岩心孔隙度来看，储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素，探索影响压裂液油水置换的关键影响因素，得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明，各参数对渗吸速度的影响顺序为：界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大，渗吸采收率越大，但是增幅逐渐减小；原油黏度越小，渗吸采收率越大；渗吸液矿化度越大，渗吸采收率越大；当渗吸液中助排剂浓度在0.005%~5%，即界面张力在0.316~10.815 mN/m范围内时，浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明：并不是界面张力越低，采收率越高，而是存在某一最佳界面张力，使地层中被绕流油的数量减少，渗吸采收率达到最高，为油田提高致密储层采收率提供实验指导。
2016, 33(1): 17-21.
doi: 10.3969/j.issn.1001-5620.2016.01.004
摘要：
目前中国页岩气水平井定向段及水平段钻井均使用油基钻井液,但油基岩屑处理费用昂贵,急需开发和应用一种具有环境保护特性的高性能水基钻井液体系。介绍了2种高性能水基钻井液体系的室内实验和现场试验效果。在长宁H9-4井水平段、长宁H9-3和长宁H9-5井定向至完井段试验了GOF高性能水基钻井液体系,该体系采用的是聚合物封堵抑制方案,完全采用水基润滑方式;在昭通区块YS108H4-2井水平段试验了高润强抑制性水基钻井液体系,该体系采用的是有机、无机盐复合防膨方案以及润滑剂与柴油复合润滑方式。现场应用表明,定向段机械钻速提高50%~75%,水平段机械钻速提高75%~100%。通过实验数据及现场使用情况,对比分析了2种体系的优劣,找出了他们各自存在的问题,并提出了改进的思路,为高性能水基钻井液的进一步完善提供一些经验。
目前中国页岩气水平井定向段及水平段钻井均使用油基钻井液,但油基岩屑处理费用昂贵,急需开发和应用一种具有环境保护特性的高性能水基钻井液体系。介绍了2种高性能水基钻井液体系的室内实验和现场试验效果。在长宁H9-4井水平段、长宁H9-3和长宁H9-5井定向至完井段试验了GOF高性能水基钻井液体系,该体系采用的是聚合物封堵抑制方案,完全采用水基润滑方式;在昭通区块YS108H4-2井水平段试验了高润强抑制性水基钻井液体系,该体系采用的是有机、无机盐复合防膨方案以及润滑剂与柴油复合润滑方式。现场应用表明,定向段机械钻速提高50%~75%,水平段机械钻速提高75%~100%。通过实验数据及现场使用情况,对比分析了2种体系的优劣,找出了他们各自存在的问题,并提出了改进的思路,为高性能水基钻井液的进一步完善提供一些经验。
2018, 35(3): 8-16.
doi: 10.3969/j.issn.1001-5620.2018.03.002
摘要：
解决环境污染问题是改善钻井液的关键，开发环保型抗高温降滤失剂是当前研究的重要领域之一。概述了国内外环保型降滤失剂的研究进展，对国内外在环保型降滤失剂研制中所使用的原材料及产品性能，以及中国抗温改性天然高分子降滤失剂的发展近况进行了介绍。天然高分子降滤失剂是通过对淀粉、纤维素及木质素等天然高分子材料进行改性以提高其抗温、抗盐能力，使其可以应用于井温更高的深井钻探中。目前，中国环保型降滤失剂普遍可以应用到150℃的高温中，部分抗温能力可达到180℃却未能推广使用。通过对现有降滤失剂的研究，分析其抗高温的作用机理，探寻能有效提高抗温能力的单体分子结构及发挥作用的功能基团，例如磺酸基团、内酰胺基团等，以期对环保型抗高温降滤失剂的研制起到一定的指导和参考作用，加快环保型抗高温降滤失剂的发展。
解决环境污染问题是改善钻井液的关键，开发环保型抗高温降滤失剂是当前研究的重要领域之一。概述了国内外环保型降滤失剂的研究进展，对国内外在环保型降滤失剂研制中所使用的原材料及产品性能，以及中国抗温改性天然高分子降滤失剂的发展近况进行了介绍。天然高分子降滤失剂是通过对淀粉、纤维素及木质素等天然高分子材料进行改性以提高其抗温、抗盐能力，使其可以应用于井温更高的深井钻探中。目前，中国环保型降滤失剂普遍可以应用到150℃的高温中，部分抗温能力可达到180℃却未能推广使用。通过对现有降滤失剂的研究，分析其抗高温的作用机理，探寻能有效提高抗温能力的单体分子结构及发挥作用的功能基团，例如磺酸基团、内酰胺基团等，以期对环保型抗高温降滤失剂的研制起到一定的指导和参考作用，加快环保型抗高温降滤失剂的发展。
2016, 33(3): 25-29.
doi: 10.3969/j.issn.1001-5620.2016.03.005
摘要：
页岩气井水平井段井壁失稳是目前中国页岩气资源勘探开发的关键技术难题。通过云南昭通108区块龙马溪组页岩的X-射线衍射分析、扫描电镜（SEM）观察、力学特性分析、润湿性、膨胀率及回收率等实验，研究了其矿物组成、微观组构特征、表面性能、膨胀和分散特性，揭示了云南昭通108区块龙马溪组页岩地层井壁水化失稳机理。该地层黏土矿物以伊利石为主要组分，不含蒙脱石及伊蒙混层，表面水化是引起页岩地层井壁失稳的主要原因。基于热力学第二定律，利用降低页岩表面自由能以抑制页岩表面水化的原理，建立了通过多碳醇吸附作用改变页岩润湿性，有效降低其表面自由能、抑制表面水化，进而显著抑制页岩水化膨胀和分散的稳定井壁方法。
页岩气井水平井段井壁失稳是目前中国页岩气资源勘探开发的关键技术难题。通过云南昭通108区块龙马溪组页岩的X-射线衍射分析、扫描电镜（SEM）观察、力学特性分析、润湿性、膨胀率及回收率等实验，研究了其矿物组成、微观组构特征、表面性能、膨胀和分散特性，揭示了云南昭通108区块龙马溪组页岩地层井壁水化失稳机理。该地层黏土矿物以伊利石为主要组分，不含蒙脱石及伊蒙混层，表面水化是引起页岩地层井壁失稳的主要原因。基于热力学第二定律，利用降低页岩表面自由能以抑制页岩表面水化的原理，建立了通过多碳醇吸附作用改变页岩润湿性，有效降低其表面自由能、抑制表面水化，进而显著抑制页岩水化膨胀和分散的稳定井壁方法。
2020, 37(6): 685-693.
doi: 10.3969/j.issn.1001-5620.2020.06.002
Abstract:
2016, 33(5): 1-8.
doi: 10.3969/j.issn.1001-5620.2016.05.001
Abstract:
2016, 33(6): 1-9.
doi: 10.3969/j.issn.1001-5620.2016.06.001
Abstract:
2017, 34(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2017.01.001
Abstract:
2016, 33(6): 45-50.
doi: 10.3969/j.issn.1001-5620.2016.06.008
Abstract:
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2018, 35(1): 101-104.
doi: 10.3969/j.issn.1001-5620.2018.01.019
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
Abstract:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2018, 35(1): 71-76.
doi: 10.3969/j.issn.1001-5620.2018.01.014
Abstract:
Governed by：
China National Petroleum Corporation Ltd
China National Petroleum Corporation Ltd
Sponsored by：
CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
Editor-in-Chief：Shi-chun Chen（Engineer Technology Research Institute,BHDC）
Deputy Editor-in-chief：
Gui-juan Wang（Engineer Technology Research Institute,BHDC）Qiang Ren（Engineer Technology Research Institute,BHDC）
Address：
Editorial Office of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province
Editorial Office of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province
Postcode： 062552
Tel：（0317）2725487 2722354
E-mail： zjyywjy@126.com
CN 12-1486/TE
ISSN 1001-5620
