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3 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
4 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
5 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
6 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
7 A New Fracturing Fluid with Temperature Resistance of 230℃
8 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
9 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
10 Progress in Studying Cement Sheath Failure in Perforated Wells
1 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
3 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
4 Challenges, Developments, and Suggestions for Drilling Fluid Technology in China
5 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
6 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
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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2026, 43(2): 145-151, 160.
doi: 10.12358/j.issn.1001-5620.2026.02.001
Abstract:
Wellbore working fluids are critical enabling technologies for the safe and efficient exploration and development of unconventional, deep, and ultra-deep oil and gas resources. This paper reviews and benchmarks domestic and international advances in wellbore fluid technologies. The results show that comparable performance has been achieved in high-performance water-based drilling fluids for unconventional reservoirs and in wellbore fluids for deep and ultra-deep applications, while notable gaps remain in reservoir protection technologies and intelligent control systems. With the continuous deepening of exploration and development, existing wellbore working fluids are still insufficient to meet the increasing demands of deeper, longer, and smarter drilling operations. Therefore, further efforts are required to promote iterative upgrading toward environmentally friendly, high-performance, and intelligent wellbore fluid systems, and to develop fully autonomous formulations integrated with advanced testing and control technologies.
Wellbore working fluids are critical enabling technologies for the safe and efficient exploration and development of unconventional, deep, and ultra-deep oil and gas resources. This paper reviews and benchmarks domestic and international advances in wellbore fluid technologies. The results show that comparable performance has been achieved in high-performance water-based drilling fluids for unconventional reservoirs and in wellbore fluids for deep and ultra-deep applications, while notable gaps remain in reservoir protection technologies and intelligent control systems. With the continuous deepening of exploration and development, existing wellbore working fluids are still insufficient to meet the increasing demands of deeper, longer, and smarter drilling operations. Therefore, further efforts are required to promote iterative upgrading toward environmentally friendly, high-performance, and intelligent wellbore fluid systems, and to develop fully autonomous formulations integrated with advanced testing and control technologies.
2026, 43(2): 152-160.
doi: 10.12358/j.issn.1001-5620.2026.02.002
Abstract:
To deal with the wellbore collapse and instability problems encountered in drilling the broken marine carbonate formations in Shunbei and western Sichuan, a visual true triaxial wellbore instability physical simulation experimental platform was prepared and used to study the microstructural characteristics, physiochemical characteristics and mechanical properties of the broken formations, and it was understood that concentrated geostress, formation fragmentation and the mechanical-chemical coupling effect between the drilling fluid and the rocks are the main controlling factors for wellbore instability. By introducing a formation integrity coefficient, a parameter relationship between the “formation integrity coefficient + drilling fluid soaking” and formation mechanics was established. Based on finite element simulation, the distribution of the geostress of the broken formations was revealed. Based on equivalent rock mechanics parameters and taking into account the chemical interaction between drilling fluid and rock, a collapse pressure prediction model based on M-C criterion was constructed. The prediction accuracy of collapse pressure in typical wells, such as the well SHB9X, PZ5-3D and PZ6-5D, is as high as 86.0%-93.9%.
To deal with the wellbore collapse and instability problems encountered in drilling the broken marine carbonate formations in Shunbei and western Sichuan, a visual true triaxial wellbore instability physical simulation experimental platform was prepared and used to study the microstructural characteristics, physiochemical characteristics and mechanical properties of the broken formations, and it was understood that concentrated geostress, formation fragmentation and the mechanical-chemical coupling effect between the drilling fluid and the rocks are the main controlling factors for wellbore instability. By introducing a formation integrity coefficient, a parameter relationship between the “formation integrity coefficient + drilling fluid soaking” and formation mechanics was established. Based on finite element simulation, the distribution of the geostress of the broken formations was revealed. Based on equivalent rock mechanics parameters and taking into account the chemical interaction between drilling fluid and rock, a collapse pressure prediction model based on M-C criterion was constructed. The prediction accuracy of collapse pressure in typical wells, such as the well SHB9X, PZ5-3D and PZ6-5D, is as high as 86.0%-93.9%.
2026, 43(2): 161-171.
doi: 10.12358/j.issn.1001-5620.2026.02.003
Abstract:
The Ordovician buried-hill reservoir in Liaohe Oilfield exhibits a challenging high-temperature (200 ℃ at reservoir center) and low-pressure (pressure coefficient 1.01～1.06) environment characteristic of typical high-temperature, low-pressure oil/gas reservoirs. To achieve formation protection, a solids-free water based drilling fluid was prioritized, with tackifier selection being critical. Through molecular structure optimization, a novel high-temperature/salt-resistant tackifier was developed using four monomers: N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), N,N-diethylacrylamide (DEAA), and 1-(3-sulfopropyl)-2-vinylpyridinium hydroxide inner salt. The synthesis employed N,N'-methylene bisacrylamide as crosslinker with potassium persulfate and sodium bisulfite as redox initiators. FTIR and TGA analysis confirmed successful polymerization, demonstrating superior thermal stability with 296.66 ℃ initial decomposition temperature and only 45.96% mass loss during degradation phase, outperforming commercial HE300. The fluid achieved remarkable rheological performance with 722 consistency coefficient (K) at 0.5% concentration. Laboratory evaluations verified exceptional thermal stability up to 220 ℃ and saturated salt tolerance. Field applications demonstrated excellent viscosity-enhancing performance and robust durability of this novel tackifier, providing vital technical support for buried-hill reservoir development and high-temperature formation drilling operations.
The Ordovician buried-hill reservoir in Liaohe Oilfield exhibits a challenging high-temperature (200 ℃ at reservoir center) and low-pressure (pressure coefficient 1.01～1.06) environment characteristic of typical high-temperature, low-pressure oil/gas reservoirs. To achieve formation protection, a solids-free water based drilling fluid was prioritized, with tackifier selection being critical. Through molecular structure optimization, a novel high-temperature/salt-resistant tackifier was developed using four monomers: N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), N,N-diethylacrylamide (DEAA), and 1-(3-sulfopropyl)-2-vinylpyridinium hydroxide inner salt. The synthesis employed N,N'-methylene bisacrylamide as crosslinker with potassium persulfate and sodium bisulfite as redox initiators. FTIR and TGA analysis confirmed successful polymerization, demonstrating superior thermal stability with 296.66 ℃ initial decomposition temperature and only 45.96% mass loss during degradation phase, outperforming commercial HE300. The fluid achieved remarkable rheological performance with 722 consistency coefficient (K) at 0.5% concentration. Laboratory evaluations verified exceptional thermal stability up to 220 ℃ and saturated salt tolerance. Field applications demonstrated excellent viscosity-enhancing performance and robust durability of this novel tackifier, providing vital technical support for buried-hill reservoir development and high-temperature formation drilling operations.
2026, 43(2): 172-178.
doi: 10.12358/j.issn.1001-5620.2026.02.004
Abstract:
Current bridging lost circulation materials (LCMs) exhibit poor lost circulation control performance and limited pressure bearing capacity when used in controlling mud losses into complex fractured formations such as those with multiscale fractures and stress-sensitive fractures, and mud losses controlled with these LCMs are easy to re-occur. Based on the idea of enhancing the elasticity and toughness as well as the volumetric expandability of the LCMs, an elastic expanding bridging efficiency-enhancing material was developed. The optimal synthesis formula and conditions were obtained through component optimization experiments. Laboratory evaluations were conducted on the material mechanics, expansion performance and lost circulation control capacity of the elastic expanding bridging efficiency-enhancing material, followed by field application. The research findings show that the elastic expanding bridging efficiency-enhancing material exhibits high compressive strength and good elasticity-toughness before and after expansion. After aging at 160 ℃, the volume of the elastic expanding bridging efficiency-enhancing material can expand to 116.67% of its original volume. Through elastic-tough deformation and continuous three-dimensional expansion, the elastic expanding bridging efficiency-enhancing material can enhance the compactness of the plugging layers and improve their elasticity-toughness, thereby strengthening the pressure-bearing and anti-breathing capacity of the seal. Preliminary field applications of this elastic expanding bridging efficiency-enhancing material in wells with lost circulation in the southwest drilling block have achieved favorable results in mud loss control, demonstrating broad promotion prospects.
Current bridging lost circulation materials (LCMs) exhibit poor lost circulation control performance and limited pressure bearing capacity when used in controlling mud losses into complex fractured formations such as those with multiscale fractures and stress-sensitive fractures, and mud losses controlled with these LCMs are easy to re-occur. Based on the idea of enhancing the elasticity and toughness as well as the volumetric expandability of the LCMs, an elastic expanding bridging efficiency-enhancing material was developed. The optimal synthesis formula and conditions were obtained through component optimization experiments. Laboratory evaluations were conducted on the material mechanics, expansion performance and lost circulation control capacity of the elastic expanding bridging efficiency-enhancing material, followed by field application. The research findings show that the elastic expanding bridging efficiency-enhancing material exhibits high compressive strength and good elasticity-toughness before and after expansion. After aging at 160 ℃, the volume of the elastic expanding bridging efficiency-enhancing material can expand to 116.67% of its original volume. Through elastic-tough deformation and continuous three-dimensional expansion, the elastic expanding bridging efficiency-enhancing material can enhance the compactness of the plugging layers and improve their elasticity-toughness, thereby strengthening the pressure-bearing and anti-breathing capacity of the seal. Preliminary field applications of this elastic expanding bridging efficiency-enhancing material in wells with lost circulation in the southwest drilling block have achieved favorable results in mud loss control, demonstrating broad promotion prospects.
2026, 43(2): 179-187.
doi: 10.12358/j.issn.1001-5620.2026.02.005
Abstract:
The Kunteyi gas field is located in the #1 buried structure of the Kunteyi sag on the northern margin of the Qaidam Basin, the bedrock reservoirs of which are developed with fractures and have a weathering crust, and the formations of which have weak segments and natural channels for mud losses, together with complex geological conditions such as ultra-high temperatures (approximately 200 ℃) and abnormal high pressures (pressure coefficient up to 1.63). To address the drilling fluid challenges confronted in drilling ultra-high temperature bedrock reservoir formations, such as thick and loose mud cakes, low pressure-bearing capacity and ease of lost circulation etc., an ultra-high temperature drilling fluid with high plugging capacity for the prevention of lost circulation was developed through synergistic design of core additives. In the drilling fluid “SC-200+Redu240” are used to construct a high-temperature colloidally stable framework, and “nano-silica + white asphalt NFA-25” used to achieve plugging of the multiscale fractures and finally an integrated function of “filtration control + fracture plugging + wellbore stability” is realized. Experimental results confirm that this drilling fluid functions normally at temperatures up to 200 ℃. After aging, the rates of change in the apparent viscosity and plastic viscosity are both less than 3%, the high-temperature high-pressure filtration rate is less than 12 mL, and the drilling fluid can resist contamination by 15%NaCl. Additionally, the sand-bed filtration rate of the drilling fluid after aging is only 4.2 mL, and the filtration rate for fracture plugging is 8.6 mL, indicating that the drilling fluid has excellent fracture plugging capacity and formation pressure-bearing capacity. This drilling fluid exhibits remarkable effects in lost circulation control and wellbore stabilization in drilling ultra-high temperature fractured formations. In field application of this drilling fluid in the well K2-3 (well depth 7170 m, and bottomhole temperature 199.5 ℃), “zero mud loss” was achieved in drilling the bedrock section, and no downhole complex situation caused by lost circulation or drilling fluid properties occurred throughout the whole drilling process, with a complex time efficiency of zero. The application of this drilling fluid technology significantly reduced the non-productive time due to lost circulation, providing reliable technical support for the safe and efficient drilling of ultra-deep wells in this area.
The Kunteyi gas field is located in the #1 buried structure of the Kunteyi sag on the northern margin of the Qaidam Basin, the bedrock reservoirs of which are developed with fractures and have a weathering crust, and the formations of which have weak segments and natural channels for mud losses, together with complex geological conditions such as ultra-high temperatures (approximately 200 ℃) and abnormal high pressures (pressure coefficient up to 1.63). To address the drilling fluid challenges confronted in drilling ultra-high temperature bedrock reservoir formations, such as thick and loose mud cakes, low pressure-bearing capacity and ease of lost circulation etc., an ultra-high temperature drilling fluid with high plugging capacity for the prevention of lost circulation was developed through synergistic design of core additives. In the drilling fluid “SC-200+Redu240” are used to construct a high-temperature colloidally stable framework, and “nano-silica + white asphalt NFA-25” used to achieve plugging of the multiscale fractures and finally an integrated function of “filtration control + fracture plugging + wellbore stability” is realized. Experimental results confirm that this drilling fluid functions normally at temperatures up to 200 ℃. After aging, the rates of change in the apparent viscosity and plastic viscosity are both less than 3%, the high-temperature high-pressure filtration rate is less than 12 mL, and the drilling fluid can resist contamination by 15%NaCl. Additionally, the sand-bed filtration rate of the drilling fluid after aging is only 4.2 mL, and the filtration rate for fracture plugging is 8.6 mL, indicating that the drilling fluid has excellent fracture plugging capacity and formation pressure-bearing capacity. This drilling fluid exhibits remarkable effects in lost circulation control and wellbore stabilization in drilling ultra-high temperature fractured formations. In field application of this drilling fluid in the well K2-3 (well depth 7170 m, and bottomhole temperature 199.5 ℃), “zero mud loss” was achieved in drilling the bedrock section, and no downhole complex situation caused by lost circulation or drilling fluid properties occurred throughout the whole drilling process, with a complex time efficiency of zero. The application of this drilling fluid technology significantly reduced the non-productive time due to lost circulation, providing reliable technical support for the safe and efficient drilling of ultra-deep wells in this area.
2026, 43(2): 188-193.
doi: 10.12358/j.issn.1001-5620.2026.02.006
Abstract:
Using environmentally friendly ester derivatives such as epoxy fatty acid esters as raw materials, react with polyamines to form a main emulsifier with a Gemini surfactant structure. Then, using the main emulsifier as raw material, partially sulfonate it to form a multi class environmentally friendly emulsifier with a similar structure for oil-based drilling fluids. The molecular structure of the emulsifier was determined through infrared and mass spectrometry characterization, with a temperature resistance of up to 180 ℃, a demulsification voltage of over 900 V, and an emulsification rate of over 90%. Capable of adapting to low oil-water ratio oil-based drilling fluid environments and drilling fluid systems formulated with different base oils. Adapt to drilling fluid systems with different densities. Has excellent biodegradability. A method for evaluating the microstructure of emulsion droplets was established to determine the stability of emulsion droplet formation, and it was determined that high emulsifier dosage can effectively improve the uniformity and high-temperature stability of oil in water emulsion droplets.
Using environmentally friendly ester derivatives such as epoxy fatty acid esters as raw materials, react with polyamines to form a main emulsifier with a Gemini surfactant structure. Then, using the main emulsifier as raw material, partially sulfonate it to form a multi class environmentally friendly emulsifier with a similar structure for oil-based drilling fluids. The molecular structure of the emulsifier was determined through infrared and mass spectrometry characterization, with a temperature resistance of up to 180 ℃, a demulsification voltage of over 900 V, and an emulsification rate of over 90%. Capable of adapting to low oil-water ratio oil-based drilling fluid environments and drilling fluid systems formulated with different base oils. Adapt to drilling fluid systems with different densities. Has excellent biodegradability. A method for evaluating the microstructure of emulsion droplets was established to determine the stability of emulsion droplet formation, and it was determined that high emulsifier dosage can effectively improve the uniformity and high-temperature stability of oil in water emulsion droplets.
2026, 43(2): 194-201.
doi: 10.12358/j.issn.1001-5620.2026.02.007
Abstract:
In high-temperature and ultra-high-temperature drilling operations, the decrease in drilling fluid gel strengths causes the settling stability and the sand carrying capacity of the drilling fluid to reduce, which results in uneven dispersion of the solid particles and cuttings agglomeration in the drilling fluid. To address this problem, a quaternary polymer drilling fluid suspending agent, XFJ-3#, which exhibits temperature resistance up to 230 ℃, was designed and synthesized using AMPS (2-acrylamido-2-methylpropanesulfonic acid), SAS (sodium allylsulfonate), SSS (sodium p-styrenesulfonate) and MBA (methylene bisacrylamide) as the main raw materials. Fourier transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA) and 1H nuclear magnetic resonance spectroscopy (1H-NMR) were used to characterize XFJ-3#. The results show that XFJ-3# is the target product. XFJ-3# loses only 60% of its weight at 600 ℃. Performance evaluation results show that a 5% Bohai drilling clay slurry treated with 1%XFJ-3# retains more than 70% of its gel strengths after aging at 230 ℃ for 10 days. The suspending agent XFJ-3# can effectively improve the ability of a drilling fluid to maintain its settling stability for a long time under ultra-high temperature environments.
In high-temperature and ultra-high-temperature drilling operations, the decrease in drilling fluid gel strengths causes the settling stability and the sand carrying capacity of the drilling fluid to reduce, which results in uneven dispersion of the solid particles and cuttings agglomeration in the drilling fluid. To address this problem, a quaternary polymer drilling fluid suspending agent, XFJ-3#, which exhibits temperature resistance up to 230 ℃, was designed and synthesized using AMPS (2-acrylamido-2-methylpropanesulfonic acid), SAS (sodium allylsulfonate), SSS (sodium p-styrenesulfonate) and MBA (methylene bisacrylamide) as the main raw materials. Fourier transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA) and 1H nuclear magnetic resonance spectroscopy (1H-NMR) were used to characterize XFJ-3#. The results show that XFJ-3# is the target product. XFJ-3# loses only 60% of its weight at 600 ℃. Performance evaluation results show that a 5% Bohai drilling clay slurry treated with 1%XFJ-3# retains more than 70% of its gel strengths after aging at 230 ℃ for 10 days. The suspending agent XFJ-3# can effectively improve the ability of a drilling fluid to maintain its settling stability for a long time under ultra-high temperature environments.
2026, 43(2): 202-208.
doi: 10.12358/j.issn.1001-5620.2026.02.008
Abstract:
Basic zinc carbonate is a commonly used sulfide scavenger for drilling high-sulfide content formations with water-based drilling fluids, its ability to remove sulfide and the mechanism of sulfide removal in oil-based drilling fluids are still not well understood. In evaluating the rate if hydrogen sulfide removal, conventional methods use relatively low concentration and flow rate of hydrogen sulfide, the results of these methods are not suitable for high temperature application, and the reaction time in these methods is too short. To overcome these deficiencies of the old evaluation methods, a new experimental platform for evaluating the rate of sulfide scavenging of deep-well drilling fluids has been constructed. Using this platform, the rates of sulfide scavenging of basic zinc carbonate in oil, water, water-in-oil emulsion and oil-based drilling fluid were tested; the test results were used to analyze the existence forms of hydrogen sulfide in water-in-oil emulsions, the sulfide scavenging mechanisms of basic zinc carbonate in neutral and weakly-alkaline aqueous phases were clarified, and the sulfide scavenging mechanism of basic zinc carbonate in oil-based drilling fluids was then revealed. The test results show that the rate of sulfide scavenging of basic zinc carbonate in oil-based drilling fluids can be as high as 100%; most of the hydrogen sulfide (>90%) invading into an oil-based drilling fluid exists as undissociated hydrogen sulfide molecules in the oil phase of the oil-based drilling fluid, and only a small fraction (<10%) of the invading hydrogen sulfide dissolves into the aqueous phase to form ions dominated by HS−. In the aqueous phase of an oil-based drilling fluid, the Zn2+ ions ionized from basic zinc carbonate react directly with the primary ionization product HS− of hydrogen sulfide to form ZnS precipitate, and a high pH of the aqueous phase is not a necessary condition for sulfide scavenging; the reaction-diffusion coupling effect is the primary mechanism of sulfide scavenging by basic zinc carbonate in oil-based drilling fluids, and temperature increase is helpful to enhance the rate of sulfide scavenging. The revealed working mechanism of basic zinc carbonate in oil-based drilling fluids provides a scientific basis for using this chemical as a sulfide scavenger in oil-based drilling fluids.
Basic zinc carbonate is a commonly used sulfide scavenger for drilling high-sulfide content formations with water-based drilling fluids, its ability to remove sulfide and the mechanism of sulfide removal in oil-based drilling fluids are still not well understood. In evaluating the rate if hydrogen sulfide removal, conventional methods use relatively low concentration and flow rate of hydrogen sulfide, the results of these methods are not suitable for high temperature application, and the reaction time in these methods is too short. To overcome these deficiencies of the old evaluation methods, a new experimental platform for evaluating the rate of sulfide scavenging of deep-well drilling fluids has been constructed. Using this platform, the rates of sulfide scavenging of basic zinc carbonate in oil, water, water-in-oil emulsion and oil-based drilling fluid were tested; the test results were used to analyze the existence forms of hydrogen sulfide in water-in-oil emulsions, the sulfide scavenging mechanisms of basic zinc carbonate in neutral and weakly-alkaline aqueous phases were clarified, and the sulfide scavenging mechanism of basic zinc carbonate in oil-based drilling fluids was then revealed. The test results show that the rate of sulfide scavenging of basic zinc carbonate in oil-based drilling fluids can be as high as 100%; most of the hydrogen sulfide (>90%) invading into an oil-based drilling fluid exists as undissociated hydrogen sulfide molecules in the oil phase of the oil-based drilling fluid, and only a small fraction (<10%) of the invading hydrogen sulfide dissolves into the aqueous phase to form ions dominated by HS−. In the aqueous phase of an oil-based drilling fluid, the Zn2+ ions ionized from basic zinc carbonate react directly with the primary ionization product HS− of hydrogen sulfide to form ZnS precipitate, and a high pH of the aqueous phase is not a necessary condition for sulfide scavenging; the reaction-diffusion coupling effect is the primary mechanism of sulfide scavenging by basic zinc carbonate in oil-based drilling fluids, and temperature increase is helpful to enhance the rate of sulfide scavenging. The revealed working mechanism of basic zinc carbonate in oil-based drilling fluids provides a scientific basis for using this chemical as a sulfide scavenger in oil-based drilling fluids.
2026, 43(2): 209-216.
doi: 10.12358/j.issn.1001-5620.2026.02.009
Abstract:
In wells for carbon capture, utilization and storage (CCUS), cement sheaths are easy to get chemically damaged, hence reducing their service life. A study was conducted to enhance the self-healing capacity of cement sheaths by reacting calcium-based whisker self-healing agent with CO2 to produce CaCO3. The influence of calcium-based whisker self-healing agent on the self-healing process of cement sheaths was studied using mechanical tester, X-ray diffractometer (XRD), thermogravimetric analyzer (TGA), scanning electron microscope (SEM) and industrial computed tomography (CT) etc. The results of mechanical performance tests showed that after 28 days of self-healing, the self-healing rate of the compressive strength of the set cement incorporated with the calcium-based whisker reached 83.87%, which is 90.31% higher than that of the set cement without incorporating calcium-based whisker. Phase analysis and SEM observation results show that a large number of calcite-type calcium carbonate crystals were generated around the self-healing material and deposited in the cracks of the set cement, thereby rendering the cracks in the set cement carbonized self-healing. CT test results further confirmed the self-healing effect of the calcium-based whisker self-healing agent; after 28 days of self-healing, the volume of the cracks in the set cement incorporated with the calcium-based whisker self-healing agent was reduced by 4,165.95 mm3, a self-healing rate of 72.32%. This indicates that in the CCUS well environment, the incorporation of calcium-based whisker self-healing materials into a cement slurry has a positive impact on the carbonized self-healing process of the cement sheath.
In wells for carbon capture, utilization and storage (CCUS), cement sheaths are easy to get chemically damaged, hence reducing their service life. A study was conducted to enhance the self-healing capacity of cement sheaths by reacting calcium-based whisker self-healing agent with CO2 to produce CaCO3. The influence of calcium-based whisker self-healing agent on the self-healing process of cement sheaths was studied using mechanical tester, X-ray diffractometer (XRD), thermogravimetric analyzer (TGA), scanning electron microscope (SEM) and industrial computed tomography (CT) etc. The results of mechanical performance tests showed that after 28 days of self-healing, the self-healing rate of the compressive strength of the set cement incorporated with the calcium-based whisker reached 83.87%, which is 90.31% higher than that of the set cement without incorporating calcium-based whisker. Phase analysis and SEM observation results show that a large number of calcite-type calcium carbonate crystals were generated around the self-healing material and deposited in the cracks of the set cement, thereby rendering the cracks in the set cement carbonized self-healing. CT test results further confirmed the self-healing effect of the calcium-based whisker self-healing agent; after 28 days of self-healing, the volume of the cracks in the set cement incorporated with the calcium-based whisker self-healing agent was reduced by 4,165.95 mm3, a self-healing rate of 72.32%. This indicates that in the CCUS well environment, the incorporation of calcium-based whisker self-healing materials into a cement slurry has a positive impact on the carbonized self-healing process of the cement sheath.
2026, 43(2): 217-222.
doi: 10.12358/j.issn.1001-5620.2026.02.010
Abstract:
Hydrated calcium silicate/polycarboxylic acid nanocrystalline species (C-S-H/PCE) is a kind of nanocomposites with nucleation effect can accelerate the hydration reaction of cement and improve the early strength of cement stone, but the conventional anionic polycarboxylic acid dispersant has strong retarding effect. In this paper, a strongly dispersing and weakly retarding amphoteric polycarboxylic acid dispersant (APC) was firstly synthesized by introducing methacryloyloxyethyltrimethylammonium chloride cationic monomer, and then a hydrated calcium silicate/amphoteric polycarboxylic acid nanocrystalline seed (C-S-H/APC) with high early-strength performance was prepared from the APC, and the structure of the crystal seed was characterized. The compressive strength of C-S-H/APC cementite was 10.8%, 8.2% and 8.9% higher than that of C-S-H/PCE cementite when the addition amount of the crystalline seed was 1%, and the curing time at 20 ℃ was 6 h, 12 h and 24 h. The XRD patterns of C-S-H/APC cementite showed that the Ca(OH)2 diffraction peaks were obviously stronger than that of the blank group, while those of C2S and C3S were lower than that of the blank group, and there were some water-induced and water-soluble peaks in the XRD patterns of the cementite. C2S, C3S, and the diffraction peaks of hydration product AFt were lower than those of the blank group. The SEM image of cement stone shows that the hydration degree of the blank cement stone is very low and the structure is loose, and the structure of the nanometer C-S-H/APC cement stone with the same age of maintenance is denser and the hydration degree of the cement is higher, which indicates that the nanometer C-S-H/APC improves the hydration rate of the cement and accelerates the formation of the spatial network structure of the hydration products, so as to improve the early strength of the cement stone, and the performance of this low-temperature early-strengthening agent slurry system is stable, and it has been used in Changqing Oil Industry. The low-temperature early strength cement slurry performs well and has been successfully applied in the low-temperature wells in the long 6 layers of Ordos Basin of Changqing Oilfield.
Hydrated calcium silicate/polycarboxylic acid nanocrystalline species (C-S-H/PCE) is a kind of nanocomposites with nucleation effect can accelerate the hydration reaction of cement and improve the early strength of cement stone, but the conventional anionic polycarboxylic acid dispersant has strong retarding effect. In this paper, a strongly dispersing and weakly retarding amphoteric polycarboxylic acid dispersant (APC) was firstly synthesized by introducing methacryloyloxyethyltrimethylammonium chloride cationic monomer, and then a hydrated calcium silicate/amphoteric polycarboxylic acid nanocrystalline seed (C-S-H/APC) with high early-strength performance was prepared from the APC, and the structure of the crystal seed was characterized. The compressive strength of C-S-H/APC cementite was 10.8%, 8.2% and 8.9% higher than that of C-S-H/PCE cementite when the addition amount of the crystalline seed was 1%, and the curing time at 20 ℃ was 6 h, 12 h and 24 h. The XRD patterns of C-S-H/APC cementite showed that the Ca(OH)2 diffraction peaks were obviously stronger than that of the blank group, while those of C2S and C3S were lower than that of the blank group, and there were some water-induced and water-soluble peaks in the XRD patterns of the cementite. C2S, C3S, and the diffraction peaks of hydration product AFt were lower than those of the blank group. The SEM image of cement stone shows that the hydration degree of the blank cement stone is very low and the structure is loose, and the structure of the nanometer C-S-H/APC cement stone with the same age of maintenance is denser and the hydration degree of the cement is higher, which indicates that the nanometer C-S-H/APC improves the hydration rate of the cement and accelerates the formation of the spatial network structure of the hydration products, so as to improve the early strength of the cement stone, and the performance of this low-temperature early-strengthening agent slurry system is stable, and it has been used in Changqing Oil Industry. The low-temperature early strength cement slurry performs well and has been successfully applied in the low-temperature wells in the long 6 layers of Ordos Basin of Changqing Oilfield.
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。
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(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%。
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。
2020, 37(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2020.01.001
摘要：
废弃钻井液污染大、种类多、处理难，给水质和土壤环境带来巨大的负面影响，随着近些年环保法规的日益完善，对废弃钻井液的处理技术也提出了新要求。概述了9种不同处理方法及其发展现状，重点分析了固化法、热解吸法、化学强化固液分离法、不落地技术和多种技术联用等处理技术，并对几种现行的主流处理技术进行了对比，指出了各类方法的发展前景，得出多种技术联用具有较好的发展潜力。分析认为今后的研究方向与热点在于如何低能耗、高效率地实现对废弃钻井液的资源化处理，具体工作既要包含污染物的源头、过程和结果控制，也要加强管理和相关制度的建立，综合开发新技术。
废弃钻井液污染大、种类多、处理难，给水质和土壤环境带来巨大的负面影响，随着近些年环保法规的日益完善，对废弃钻井液的处理技术也提出了新要求。概述了9种不同处理方法及其发展现状，重点分析了固化法、热解吸法、化学强化固液分离法、不落地技术和多种技术联用等处理技术，并对几种现行的主流处理技术进行了对比，指出了各类方法的发展前景，得出多种技术联用具有较好的发展潜力。分析认为今后的研究方向与热点在于如何低能耗、高效率地实现对废弃钻井液的资源化处理，具体工作既要包含污染物的源头、过程和结果控制，也要加强管理和相关制度的建立，综合开发新技术。
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。
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。
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。
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:
2017, 34(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2017.01.001
Abstract:
2016, 33(6): 1-9.
doi: 10.3969/j.issn.1001-5620.2016.06.001
Abstract:
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2016, 33(6): 45-50.
doi: 10.3969/j.issn.1001-5620.2016.06.008
Abstract:
2018, 35(1): 101-104.
doi: 10.3969/j.issn.1001-5620.2018.01.019
Abstract:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
Abstract:
2016, 33(6): 10-16.
doi: 10.3969/j.issn.1001-5620.2016.06.002
Abstract:
Governed by：
China National Petroleum Corporation Ltd
China National Petroleum Corporation Ltd
Sponsored by：
CNPC Bohai Drilling Engineering Co. Ltd
CNPC Bohai Drilling Engineering Co. Ltd
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：
Room A517, China Petroleum Tianjin Building, No. 83, Second Avenue, Tianjin Economic and Technological Development Zone
Room A517, China Petroleum Tianjin Building, No. 83, Second Avenue, Tianjin Economic and Technological Development Zone
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E-mail： zjyywjy@126.com
CN 12-1486/TE
ISSN 1001-5620
