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3 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
4 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
5 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
6 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
7 Progress in Studying Cement Sheath Failure in Perforated Wells
8 A New Fracturing Fluid with Temperature Resistance of 230℃
9 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
10 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
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 Model for Predicting Drilling Fluid Rheological Parameters in Wide Temperature and Pressure Range
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(5): 577-583.
doi: 10.12358/j.issn.1001-5620.2026.05.001
Abstract:
Oil-based drilling fluids in recent years have been widely used in drilling high-temperature deep wells, ultra-deep wells, strongly water-sensitive shales and salt-rock formations, as well as complexly-structured wells demanding high lubricity such as extended-reach horizontal wells, fishbone-type wells and multilateral wells. However, oil-based drilling fluids cause serious environmental pollution, and their application is also restricted by these factors such as high cost and the availability of core additives (such as emulsifiers). Using low oil/water ratio oil-based drilling fluids, the cost can be significantly reduced, the requirements for the performance of emulsifiers are stringent though. In recent years, research efforts both in China and abroad have been devoted to the development of high-performance emulsifiers and a series of low oil/water ratio oil-based drilling fluids have been developed. This paper reviews the emulsifier technology for low oil/water ratio oil-based drilling fluids and oil-based drilling fluids of different oil/water ratios both in China and abroad, and analyzes the research progress and existing challenges encountered in the development of low oil/water ratio oil-based drilling fluids to try to provide a guidance for the future research and development of this drilling fluid technology.
Oil-based drilling fluids in recent years have been widely used in drilling high-temperature deep wells, ultra-deep wells, strongly water-sensitive shales and salt-rock formations, as well as complexly-structured wells demanding high lubricity such as extended-reach horizontal wells, fishbone-type wells and multilateral wells. However, oil-based drilling fluids cause serious environmental pollution, and their application is also restricted by these factors such as high cost and the availability of core additives (such as emulsifiers). Using low oil/water ratio oil-based drilling fluids, the cost can be significantly reduced, the requirements for the performance of emulsifiers are stringent though. In recent years, research efforts both in China and abroad have been devoted to the development of high-performance emulsifiers and a series of low oil/water ratio oil-based drilling fluids have been developed. This paper reviews the emulsifier technology for low oil/water ratio oil-based drilling fluids and oil-based drilling fluids of different oil/water ratios both in China and abroad, and analyzes the research progress and existing challenges encountered in the development of low oil/water ratio oil-based drilling fluids to try to provide a guidance for the future research and development of this drilling fluid technology.
2026, 43(5): 584-591.
doi: 10.12358/j.issn.1001-5620.2026.05.002
Abstract:
The Ordovician system and the Chuanxi marine carbonate formation in Shunbei oil and gas field are developed with broken formations, and borehole wall collapse have been frequently encountered during drilling. To stabilize the borehole wall with the density of the drilling fluid, it is necessary for the drilling fluid to perform well in plugging the fractured formations. Methods presently in use for evaluating the plugging capacity of a drilling fluid use porous filtration media which cannot represent the fracture development characteristics of fractured formations. To simulate the filtration behavior of a fluid in a fractured formation, a plugging capacity evaluation method was developed using slotted filter papers, thin metal sheets with acid-itched microfractures as well as 3D printed disks with fractures of various sizes, and using the thin metal-sheets with acid-itched microfractures method, the high temperature polymer sulfonate drilling fluid (mixed with oil) used on the well SHB83CH was evaluated for its microfracture plugging capacity and was then optimized. The results of the evaluation show that, for the acid-itched metal sheets method, metal sheets with 30 μm microfractures can be batch produced, and thus has the advantage of significantly higher test precision over the 3D printed disk method (the width of the fractures has deviation >50%). The number of the fractures is positively exponentially correlated with the total volume of filter loss, the width of a fracture has a quadratic function relationship with the volume of spurt filter loss, and the total volume of filter loss has a negative quadratic function relationship with the width of a fracture. An increase in the width of a fracture results in a more significant increase in the volume of the spurt filter loss, while the total volume of the filter loss tends to remain constant. The volume of the spurt filter loss can be used to evaluate the rate of mud cake formation and the effect of the mud cake on plugging the microfractures, and the total volume of filter loss can be used to evaluate the compactness of the mud cake. Field application showed that the use of the optimized drilling fluid reduced the percent hole enlargement to less than 5%. The evaluation methods established in this study provide a reliable technical means for screening plugging materials for fractured formations.
The Ordovician system and the Chuanxi marine carbonate formation in Shunbei oil and gas field are developed with broken formations, and borehole wall collapse have been frequently encountered during drilling. To stabilize the borehole wall with the density of the drilling fluid, it is necessary for the drilling fluid to perform well in plugging the fractured formations. Methods presently in use for evaluating the plugging capacity of a drilling fluid use porous filtration media which cannot represent the fracture development characteristics of fractured formations. To simulate the filtration behavior of a fluid in a fractured formation, a plugging capacity evaluation method was developed using slotted filter papers, thin metal sheets with acid-itched microfractures as well as 3D printed disks with fractures of various sizes, and using the thin metal-sheets with acid-itched microfractures method, the high temperature polymer sulfonate drilling fluid (mixed with oil) used on the well SHB83CH was evaluated for its microfracture plugging capacity and was then optimized. The results of the evaluation show that, for the acid-itched metal sheets method, metal sheets with 30 μm microfractures can be batch produced, and thus has the advantage of significantly higher test precision over the 3D printed disk method (the width of the fractures has deviation >50%). The number of the fractures is positively exponentially correlated with the total volume of filter loss, the width of a fracture has a quadratic function relationship with the volume of spurt filter loss, and the total volume of filter loss has a negative quadratic function relationship with the width of a fracture. An increase in the width of a fracture results in a more significant increase in the volume of the spurt filter loss, while the total volume of the filter loss tends to remain constant. The volume of the spurt filter loss can be used to evaluate the rate of mud cake formation and the effect of the mud cake on plugging the microfractures, and the total volume of filter loss can be used to evaluate the compactness of the mud cake. Field application showed that the use of the optimized drilling fluid reduced the percent hole enlargement to less than 5%. The evaluation methods established in this study provide a reliable technical means for screening plugging materials for fractured formations.
2026, 43(5): 592-602.
doi: 10.12358/j.issn.1001-5620.2026.05.003
Abstract:
To address the limitation of traditional particle-size matching rules in lost circulation control for multi-scale fractured formations, coupled CFD-DEM simulations and laboratory simulated fracture-plugging evaluation experiments were performed on multi-scale wedge-shaped fractures. A dimensionless stability coefficient S was defined from the pressure-drop response. Gaussian process regression (GPR) was then used to establish the response relationship of S with fracture aperture and bridging particle-size ratio, forming a particle-size matching chart for multi-scale fractures. The results show that particle plugging-layer morphology and pressure-bearing response vary with fracture size. Suitable particle-size ratios allow bridging particles to form stable packing zones inside fractures and exhibit high pressure-bearing capacity, whereas smaller or larger ratios lead to deep migration, erosion-induced instability, or false plugging at the fracture inlet. The preferred particle-size ratio is 0.25-0.40 for 0.2-1 mm fractures and 0.35-0.45 for 1.5-2.5 mm fractures. The chart agrees with experimental data, with R2=0.8674, indicating good fitting accuracy within the research range.
To address the limitation of traditional particle-size matching rules in lost circulation control for multi-scale fractured formations, coupled CFD-DEM simulations and laboratory simulated fracture-plugging evaluation experiments were performed on multi-scale wedge-shaped fractures. A dimensionless stability coefficient S was defined from the pressure-drop response. Gaussian process regression (GPR) was then used to establish the response relationship of S with fracture aperture and bridging particle-size ratio, forming a particle-size matching chart for multi-scale fractures. The results show that particle plugging-layer morphology and pressure-bearing response vary with fracture size. Suitable particle-size ratios allow bridging particles to form stable packing zones inside fractures and exhibit high pressure-bearing capacity, whereas smaller or larger ratios lead to deep migration, erosion-induced instability, or false plugging at the fracture inlet. The preferred particle-size ratio is 0.25-0.40 for 0.2-1 mm fractures and 0.35-0.45 for 1.5-2.5 mm fractures. The chart agrees with experimental data, with R2=0.8674, indicating good fitting accuracy within the research range.
2026, 43(5): 603-612.
doi: 10.12358/j.issn.1001-5620.2026.05.004
Abstract:
This study aimed to address the technical challenges of insufficient thermal stability and easy failure of the oil-water interfacial film in existing oil-based drilling fluid emulsifiers during ultra-high-temperature (>220 ℃) deep well and 10,000-meter-level ultra-deep well drilling. Based on the design concepts of rigid-skeleton-enhanced thermal stability andmulti-site adsorption,the study synthesized a novel ultra-high-temperature emulsifier (UHT-EM) featuring a double-benzene-bridged skeleton, double long-chain alkyl groups, and double calcium sulfonate head groups, using lauric acid and diphenylethane as raw materials. The molecular structure was characterized by infrared spectroscopy and proton nuclear magnetic resonance (1H NMR) spectroscopy. The emulsification performance and interfacial film strength were evaluated in terms of thermal stability, low-frequency oscillation, and microscopic morphology, and an ultra-high-temperature oil-based drilling fluid system based on UHT-EM was formulated. The results showed that the emulsion containing 1.0% UHT-EM exhibited ES of 1431 V after aging at 230 ℃ for 16 h, which remained at 729 V at 250 ℃, and dropped to 430 V at 260 ℃, significantly outperforming the emulsifiers HTM and Span80. Low-frequency oscillation tests indicated that the storage modulus G′ reached 649–801 Pa at low strain amplitudes and was consistently significantly higher than G″, demonstrating an elasticity-dominated high-strength characteristic. Microscopic morphology analysis showed that the emulsion maintained regular spherical shapes and a unimodal narrow particle size distribution within 230–250 ℃, whereas coalescence and destabilization occurred at 260 ℃ due to the synergistic failure of molecular anchoring and ionic crosslinking. The ultra-high-temperature oil-based drilling fluid formulated with UHT-EM (oil-water ratio 80∶20, density 2.0 g/cm3) achieved an ES value of 1226 V and FLHTHP of 28.0 mL after aging at 230 ℃ for 16 h. By virtue of the molecular synergy between the double-benzene-bridged rigid skeleton and the double calcium sulfonate head groups, UHT-EM significantly improved the thermal decomposition temperature and interfacial film strength, exhibiting excellent emulsification stability at 250 ℃. It can provide core material support for oil-based drilling fluids used in 10,000-meter-level ultra-deep well and ultra-high-temperature deep well drilling.
This study aimed to address the technical challenges of insufficient thermal stability and easy failure of the oil-water interfacial film in existing oil-based drilling fluid emulsifiers during ultra-high-temperature (>220 ℃) deep well and 10,000-meter-level ultra-deep well drilling. Based on the design concepts of rigid-skeleton-enhanced thermal stability andmulti-site adsorption,the study synthesized a novel ultra-high-temperature emulsifier (UHT-EM) featuring a double-benzene-bridged skeleton, double long-chain alkyl groups, and double calcium sulfonate head groups, using lauric acid and diphenylethane as raw materials. The molecular structure was characterized by infrared spectroscopy and proton nuclear magnetic resonance (1H NMR) spectroscopy. The emulsification performance and interfacial film strength were evaluated in terms of thermal stability, low-frequency oscillation, and microscopic morphology, and an ultra-high-temperature oil-based drilling fluid system based on UHT-EM was formulated. The results showed that the emulsion containing 1.0% UHT-EM exhibited ES of 1431 V after aging at 230 ℃ for 16 h, which remained at 729 V at 250 ℃, and dropped to 430 V at 260 ℃, significantly outperforming the emulsifiers HTM and Span80. Low-frequency oscillation tests indicated that the storage modulus G′ reached 649–801 Pa at low strain amplitudes and was consistently significantly higher than G″, demonstrating an elasticity-dominated high-strength characteristic. Microscopic morphology analysis showed that the emulsion maintained regular spherical shapes and a unimodal narrow particle size distribution within 230–250 ℃, whereas coalescence and destabilization occurred at 260 ℃ due to the synergistic failure of molecular anchoring and ionic crosslinking. The ultra-high-temperature oil-based drilling fluid formulated with UHT-EM (oil-water ratio 80∶20, density 2.0 g/cm3) achieved an ES value of 1226 V and FLHTHP of 28.0 mL after aging at 230 ℃ for 16 h. By virtue of the molecular synergy between the double-benzene-bridged rigid skeleton and the double calcium sulfonate head groups, UHT-EM significantly improved the thermal decomposition temperature and interfacial film strength, exhibiting excellent emulsification stability at 250 ℃. It can provide core material support for oil-based drilling fluids used in 10,000-meter-level ultra-deep well and ultra-high-temperature deep well drilling.
2026, 43(5): 613-619.
doi: 10.12358/j.issn.1001-5620.2026.05.005
Abstract:
With the ongoing expansion of oil and gas exploration into deep and ultra-deep wells, alongside escalating demands for green, low-carbon development and cost-effective efficiency, the development of drilling fluid additives that combine high-temperature resistance, low viscosity impact, environmental compatibility, and low cost has emerged as a critical direction for the industry. This study utilized lignin recovered from papermaking waste liquor as the primary raw material to successfully synthesize a high-temperature, environmentally friendly filtrate reducer—sulfonated biophenol-modified resin SMBMP-1—through alkali-oxygen degradation and graft modification processes. Experimental results demonstrate that the additive exhibits temperature resistance up to 180 ℃, salt tolerance to saturation, and calcium resistance of 3%. Its high-temperature, high-pressure fluid loss was only 14.6～15.4 mL, significantly outperforming the SMP-II industry standard (≤35 mL). Regarding environmental performance, it shows an EC50 value of 259,000 mg/L and a BOD5/CODCr ratio of 0.23, indicating it is non-toxic and readily biodegradable. Furthermore, the additive exhibits a low viscosity effect and demonstrates good compatibility within drilling fluid systems. The development of sulfonated biophenol-modified resin provides robust product support for rheological control and wellbore stability in deep and ultra-deep well drilling. It also holds significant importance for promoting the high-value utilization of biomass resources in the drilling fluid industry.
With the ongoing expansion of oil and gas exploration into deep and ultra-deep wells, alongside escalating demands for green, low-carbon development and cost-effective efficiency, the development of drilling fluid additives that combine high-temperature resistance, low viscosity impact, environmental compatibility, and low cost has emerged as a critical direction for the industry. This study utilized lignin recovered from papermaking waste liquor as the primary raw material to successfully synthesize a high-temperature, environmentally friendly filtrate reducer—sulfonated biophenol-modified resin SMBMP-1—through alkali-oxygen degradation and graft modification processes. Experimental results demonstrate that the additive exhibits temperature resistance up to 180 ℃, salt tolerance to saturation, and calcium resistance of 3%. Its high-temperature, high-pressure fluid loss was only 14.6～15.4 mL, significantly outperforming the SMP-II industry standard (≤35 mL). Regarding environmental performance, it shows an EC50 value of 259,000 mg/L and a BOD5/CODCr ratio of 0.23, indicating it is non-toxic and readily biodegradable. Furthermore, the additive exhibits a low viscosity effect and demonstrates good compatibility within drilling fluid systems. The development of sulfonated biophenol-modified resin provides robust product support for rheological control and wellbore stability in deep and ultra-deep well drilling. It also holds significant importance for promoting the high-value utilization of biomass resources in the drilling fluid industry.
2026, 43(5): 620-630.
doi: 10.12358/j.issn.1001-5620.2026.05.006
Abstract:
To explore the potential of phase change microcapsules (PCMs) in temperature regulation within ultra-deep wellbores, this study successfully prepared PCMs DM@SiO2 with D-mannitol (DM) as the core material and an inorganic shell layer of SiO2 by the sol-gel method. The morphology, chemical structure, crystal form, heat storage performance, and thermal stability of DM@SiO2 were systematically analyzed through scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD), and simultaneous thermal analysis (STA). Additionally, numerical simulations of wellbore heat transfer were conducted. The results indicated that the DM@SiO2 particles were intact with a clear core-shell structure. The phase change latent heat reached 224.59 J/g, and the encapsulation efficiency was 76.76%. Performance evaluations showed that under a high-temperature condition of 180 ℃, at addition amounts of 10% and 15%, DM@SiO2 maintained white oil at 167 ℃ for 6 min and 10 min, respectively, demonstrating a significant cooling delay effect. Meanwhile, it exhibited excellent thermal stability, shear resistance, alkali resistance, and compatibility with oil-based drilling fluids. Numerical simulation results revealed that DM@SiO2 could form a 167 ℃ isothermal phase-change zone at well depths of 9000 m and 10 000 m. In the 9 000 m well, this isothermal zone extended to the bottom hole. For the 10 000 m well, the maximum length of the isothermal zone reached 2.869 km at DM@SiO2 addition amount of 15%. DM@SiO2 could also significantly reduce the fluid temperature in the high-temperature section. DM@SiO2 holds promising application prospects for lowering wellbore temperatures during drilling fluid circulation.
To explore the potential of phase change microcapsules (PCMs) in temperature regulation within ultra-deep wellbores, this study successfully prepared PCMs DM@SiO2 with D-mannitol (DM) as the core material and an inorganic shell layer of SiO2 by the sol-gel method. The morphology, chemical structure, crystal form, heat storage performance, and thermal stability of DM@SiO2 were systematically analyzed through scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD), and simultaneous thermal analysis (STA). Additionally, numerical simulations of wellbore heat transfer were conducted. The results indicated that the DM@SiO2 particles were intact with a clear core-shell structure. The phase change latent heat reached 224.59 J/g, and the encapsulation efficiency was 76.76%. Performance evaluations showed that under a high-temperature condition of 180 ℃, at addition amounts of 10% and 15%, DM@SiO2 maintained white oil at 167 ℃ for 6 min and 10 min, respectively, demonstrating a significant cooling delay effect. Meanwhile, it exhibited excellent thermal stability, shear resistance, alkali resistance, and compatibility with oil-based drilling fluids. Numerical simulation results revealed that DM@SiO2 could form a 167 ℃ isothermal phase-change zone at well depths of 9000 m and 10 000 m. In the 9 000 m well, this isothermal zone extended to the bottom hole. For the 10 000 m well, the maximum length of the isothermal zone reached 2.869 km at DM@SiO2 addition amount of 15%. DM@SiO2 could also significantly reduce the fluid temperature in the high-temperature section. DM@SiO2 holds promising application prospects for lowering wellbore temperatures during drilling fluid circulation.
2026, 43(5): 631-639.
doi: 10.12358/j.issn.1001-5620.2026.05.007
Abstract:
High density saturated saltwater drilling fluids at 220 ℃ have rheology, filtration rate and stability that are difficult to control. To address this issue, a low-viscosity fluid loss reducer CNT/ZPE was developed. CNT/ZPE uses carbon nanotube (CNT) as the rigid carrier, and is synthesized through the cation-π and π-π stacking interactions between nitrogen cations/aromatic rings and CNTs. In a CNT/ZPE molecule, the CNT is coated with high cationicity amphoteric copolymer ZPE. Using CNT/ZPE as the sole copolymer fluid loss reducer, a high density saturated saltwater drilling fluid that can be used at temperatures up to 220 ℃ was formulated with other conventional drilling fluid additives. The results of Fourier transform infrared spectroscopy and transmission electron microscopy analyses show that the CNT/ZPE molecules contain the designed quaternary ammonium cations, benzene rings and sulfonic acid groups etc., and the surfaces of CNTs are successfully coated with high cationicity amphoteric copolymer molecules. A salt-saturated base mud (containing 36% NaCl) and a calcium base mud (containing 2% CaCl2) treated with 3% CNT/ZPE have API filtration rate of only 5.4 mL and 6.0 mL after aging at 220 ℃, respectively. The apparent viscosity (AV) of 1% CNT/ZPE water solution is only 5mPa·s, lower than the AVs of the water solutions of other regularly used low-viscosity copolymer fluid loss reducers, such as DSP-1, PSP and SO-1 at the same concentration. The formulated saturated saltwater drilling fluid, at densities between 2.0 g/cm3 and 2.3 g/cm3, have reasonable rheological parameters and controllable high-temperature high-pressure fluid loss after aging at 220 ℃ for 16 hours and 48 hours, respectively. It is resistant to the contamination of 0.7%CaCl2, and is able to satisfy the requirements of field drilling operations. This study also provides a new strategy for developing CNT-based polymer compound materials for use in drilling fluids.
High density saturated saltwater drilling fluids at 220 ℃ have rheology, filtration rate and stability that are difficult to control. To address this issue, a low-viscosity fluid loss reducer CNT/ZPE was developed. CNT/ZPE uses carbon nanotube (CNT) as the rigid carrier, and is synthesized through the cation-π and π-π stacking interactions between nitrogen cations/aromatic rings and CNTs. In a CNT/ZPE molecule, the CNT is coated with high cationicity amphoteric copolymer ZPE. Using CNT/ZPE as the sole copolymer fluid loss reducer, a high density saturated saltwater drilling fluid that can be used at temperatures up to 220 ℃ was formulated with other conventional drilling fluid additives. The results of Fourier transform infrared spectroscopy and transmission electron microscopy analyses show that the CNT/ZPE molecules contain the designed quaternary ammonium cations, benzene rings and sulfonic acid groups etc., and the surfaces of CNTs are successfully coated with high cationicity amphoteric copolymer molecules. A salt-saturated base mud (containing 36% NaCl) and a calcium base mud (containing 2% CaCl2) treated with 3% CNT/ZPE have API filtration rate of only 5.4 mL and 6.0 mL after aging at 220 ℃, respectively. The apparent viscosity (AV) of 1% CNT/ZPE water solution is only 5mPa·s, lower than the AVs of the water solutions of other regularly used low-viscosity copolymer fluid loss reducers, such as DSP-1, PSP and SO-1 at the same concentration. The formulated saturated saltwater drilling fluid, at densities between 2.0 g/cm3 and 2.3 g/cm3, have reasonable rheological parameters and controllable high-temperature high-pressure fluid loss after aging at 220 ℃ for 16 hours and 48 hours, respectively. It is resistant to the contamination of 0.7%CaCl2, and is able to satisfy the requirements of field drilling operations. This study also provides a new strategy for developing CNT-based polymer compound materials for use in drilling fluids.
2026, 43(5): 640-648.
doi: 10.12358/j.issn.1001-5620.2026.05.008
Abstract:
With the increasing depletion of shallow oil and gas resources, the exploration and development of deep and ultra-deep reservoirs have progressively become the primary focus. However, high bottomhole temperatures pose a critical challenge to the safe and efficient drilling of ultra-deep wells. This study proposes a coordinated temperature control method for drilling fluid, combining surface ice-particle cooling and downhole thermal insulation. Based on a case study of an 8,543 m ultra-deep well in the Tarim Basin, a transient wellbore heat transfer model was established to systematically analyze the influence of multiple factors on the circulating bottomhole temperature. An optimized wellbore temperature control strategy was subsequently proposed. The results demonstrate that insulating the drill pipe effectively reduces the bottomhole temperature, with performance improving as the thermal conductivity of the coating decreases. Among the operating parameters, drilling fluid flow rate has the most significant impact—bottomhole temperature decreases as the flow rate increases. Regarding thermophysical properties, heat capacity and density exhibit a stronger influence on bottomhole temperature, whereas thermal conductivity and viscosity play relatively minor roles, primarily affecting the convective heat transfer process by altering the Nusselt number. Furthermore, thermal insulation significantly enhances the cooling effect of other parameters, particularly the inlet temperature. Without insulation, reducing the inlet temperature from 80 ℃ to 0 ℃ only affects the shallow section, leaving the bottomhole temperature nearly unchanged. In contrast, with insulation, the same inlet temperature drop reduces the bottomhole temperature by approximately 28 ℃. Therefore, effective temperature control in ultra-deep wells requires the synergistic application of multiple technical measures. This study provides theoretical guidance for managing the wellbore temperature field during deep drilling operations.
With the increasing depletion of shallow oil and gas resources, the exploration and development of deep and ultra-deep reservoirs have progressively become the primary focus. However, high bottomhole temperatures pose a critical challenge to the safe and efficient drilling of ultra-deep wells. This study proposes a coordinated temperature control method for drilling fluid, combining surface ice-particle cooling and downhole thermal insulation. Based on a case study of an 8,543 m ultra-deep well in the Tarim Basin, a transient wellbore heat transfer model was established to systematically analyze the influence of multiple factors on the circulating bottomhole temperature. An optimized wellbore temperature control strategy was subsequently proposed. The results demonstrate that insulating the drill pipe effectively reduces the bottomhole temperature, with performance improving as the thermal conductivity of the coating decreases. Among the operating parameters, drilling fluid flow rate has the most significant impact—bottomhole temperature decreases as the flow rate increases. Regarding thermophysical properties, heat capacity and density exhibit a stronger influence on bottomhole temperature, whereas thermal conductivity and viscosity play relatively minor roles, primarily affecting the convective heat transfer process by altering the Nusselt number. Furthermore, thermal insulation significantly enhances the cooling effect of other parameters, particularly the inlet temperature. Without insulation, reducing the inlet temperature from 80 ℃ to 0 ℃ only affects the shallow section, leaving the bottomhole temperature nearly unchanged. In contrast, with insulation, the same inlet temperature drop reduces the bottomhole temperature by approximately 28 ℃. Therefore, effective temperature control in ultra-deep wells requires the synergistic application of multiple technical measures. This study provides theoretical guidance for managing the wellbore temperature field during deep drilling operations.
2026, 43(5): 649-660.
doi: 10.12358/j.issn.1001-5620.2026.05.009
Abstract:
To address wellbore instability in deep coalbed methane horizontal wells in the Daji Block on the eastern margin of the Ordos Basin, systematic analyses were conducted of the core mineral composition, macro- and microstructural characteristics, physicochemical properties, and mechanical properties. The rock-fluid interaction mechanisms in the deep coal rock-parting formations in this block were subsequently identified. The results show that the hydration-induced weakening of the primary cleat-fracture system in the coal rock acts synergistically with hydration-induced microfracture dilation, secondary-fracture development, and clay mineral hydration and swelling in the dark-gray argillaceous partings. The resulting deterioration in the mechanical strength of the coal rock-parting composite formation is the dominant factor controlling wellbore instability in the horizontal sections of coalbed methane wells. Based on the identified rock-fluid interaction mechanisms, a synergistic wellbore-stability strategy integrating “multistage plugging, hydrophobic inhibition, density matching, and precise control” is proposed. A drilling fluid system with strong plugging, inhibition, and supporting capabilities is developed using film-forming and hydrophobic functional additives as the core treatment agents. Laboratory performance evaluations show that all performance parameters meet the engineering requirements. Field application demonstrated that this drilling fluid system enabled the successful completion of Well JS6-3P02. The well had a 2062 m horizontal section, achieved 100% penetration of the coal-seam target interval, and required only 7 d to drill the horizontal section. The horizontal section was drilled to total depth in a single bit run without any downhole complications. It was the first deep coalbed methane horizontal well with a horizontal section exceeding 2,000 m to be completed in the Daji Block. The developed drilling fluid system meets the requirements for drilling coalbed methane wells with long horizontal sections and has good potential for wider application.
To address wellbore instability in deep coalbed methane horizontal wells in the Daji Block on the eastern margin of the Ordos Basin, systematic analyses were conducted of the core mineral composition, macro- and microstructural characteristics, physicochemical properties, and mechanical properties. The rock-fluid interaction mechanisms in the deep coal rock-parting formations in this block were subsequently identified. The results show that the hydration-induced weakening of the primary cleat-fracture system in the coal rock acts synergistically with hydration-induced microfracture dilation, secondary-fracture development, and clay mineral hydration and swelling in the dark-gray argillaceous partings. The resulting deterioration in the mechanical strength of the coal rock-parting composite formation is the dominant factor controlling wellbore instability in the horizontal sections of coalbed methane wells. Based on the identified rock-fluid interaction mechanisms, a synergistic wellbore-stability strategy integrating “multistage plugging, hydrophobic inhibition, density matching, and precise control” is proposed. A drilling fluid system with strong plugging, inhibition, and supporting capabilities is developed using film-forming and hydrophobic functional additives as the core treatment agents. Laboratory performance evaluations show that all performance parameters meet the engineering requirements. Field application demonstrated that this drilling fluid system enabled the successful completion of Well JS6-3P02. The well had a 2062 m horizontal section, achieved 100% penetration of the coal-seam target interval, and required only 7 d to drill the horizontal section. The horizontal section was drilled to total depth in a single bit run without any downhole complications. It was the first deep coalbed methane horizontal well with a horizontal section exceeding 2,000 m to be completed in the Daji Block. The developed drilling fluid system meets the requirements for drilling coalbed methane wells with long horizontal sections and has good potential for wider application.
2026, 43(5): 661-669.
doi: 10.12358/j.issn.1001-5620.2026.05.010
Abstract:
The parametric well Nidaican-1 is the first parametric well drilled in Dailekh, Nepal. Through comprehensive application of geological well logging technology, the identification of the formation lithology, the evaluation of the formation pressure while drilling, the description of reservoir physical properties, and the interpretation and evaluation of the oil/gas/water zones, have been completed, identifying the oil and gas exploration potential of this area. To tackle the difficulties in drilling the high-silica metamorphic quartz sandstones with high hardness and abrasiveness, the assembly of “MWD + single-bend PDM + turbodrill” was adopted to optimize well-path control. Coupled with the strategy of reinforcing the bit materials and bit structure, the rate of penetration was increased by at least 50%, and the footage drilled by a single bit exceeded 300 m. Using the novel potassium calcium based polymer drilling fluid, wellbore instability encountered in drilling the thrust nappe zone was successfully solved, with a rate of hole enlargement of only 6.1%. Using well cementing technology combined contamination-/lost circulation-preventive cement slurry and rigid-elastic centralizer combinations, the casing string was successfully set at a depth of 4,011 m. The integrated geological evaluation-drilling engineering technology established includes (1) drilling assembly and parameter optimization method for drilling in thrust nappe zones aimed at “preventing deviated drilling and drilling fast”; (2) strongly inhibited drilling fluid composition with high plugging capacity; and (3) standard practice for well cementing in complex structural zones. The achievements made not only fill the technical gap in deep hydrocarbon drilling in Nepal, but also bear important practical significance for promoting energy cooperation around the Himalayas.
The parametric well Nidaican-1 is the first parametric well drilled in Dailekh, Nepal. Through comprehensive application of geological well logging technology, the identification of the formation lithology, the evaluation of the formation pressure while drilling, the description of reservoir physical properties, and the interpretation and evaluation of the oil/gas/water zones, have been completed, identifying the oil and gas exploration potential of this area. To tackle the difficulties in drilling the high-silica metamorphic quartz sandstones with high hardness and abrasiveness, the assembly of “MWD + single-bend PDM + turbodrill” was adopted to optimize well-path control. Coupled with the strategy of reinforcing the bit materials and bit structure, the rate of penetration was increased by at least 50%, and the footage drilled by a single bit exceeded 300 m. Using the novel potassium calcium based polymer drilling fluid, wellbore instability encountered in drilling the thrust nappe zone was successfully solved, with a rate of hole enlargement of only 6.1%. Using well cementing technology combined contamination-/lost circulation-preventive cement slurry and rigid-elastic centralizer combinations, the casing string was successfully set at a depth of 4,011 m. The integrated geological evaluation-drilling engineering technology established includes (1) drilling assembly and parameter optimization method for drilling in thrust nappe zones aimed at “preventing deviated drilling and drilling fast”; (2) strongly inhibited drilling fluid composition with high plugging capacity; and (3) standard practice for well cementing in complex structural zones. The achievements made not only fill the technical gap in deep hydrocarbon drilling in Nepal, but also bear important practical significance for promoting energy cooperation around the Himalayas.
2024, 41(1): 1-30.
doi: 10.12358/j.issn.1001-5620.2024.01.001
摘要：
系统地梳理了超深/特深层、非常规、深水、干热岩、极地、天然气水合物等复杂地层钻探过程中面临的钻井液技术难题，探讨了关键科学问题与核心工程难题，结合近年来的钻井液技术进展，介绍了钻井液技术最新进展。针对复杂地层钻井过程中遇到的高温高压高盐、泥页岩水化严重、井壁失稳、大温差、井漏、储层损害，以及钻井液维护自动化程度低等问题，国内外学者研发了抗高温高盐水基/油基钻井液、恒流变钻井液、抗超高温泡沫钻井液、环境友好型超低温钻井液、智能温压响应承压堵漏材料、可降解储层保护材料、钻井液在线监测与自动加料系统等关键材料、体系与装备。但随着地质、工程环境愈加复杂 ，钻井液材料仍面临抗超高温高盐、超长时间稳定、防塌固壁、恶性漏失以及钻井液性能自动化调控等重大技术瓶颈。为满足复杂地层钻探过程中钻井液性能需求 ，未来还需深入研究钻井液处理剂在极端条件下的起效/失效机理 ，钻井液处理剂在微观-介观-宏观等不同尺度下的构效关系变化及作用机制，建立安全高效的钻井液多功能一体化调控方法，构建智能钻井液理论与技术，为实现复杂地层安全高效经济环保钻井提供关键技术支撑。
系统地梳理了超深/特深层、非常规、深水、干热岩、极地、天然气水合物等复杂地层钻探过程中面临的钻井液技术难题，探讨了关键科学问题与核心工程难题，结合近年来的钻井液技术进展，介绍了钻井液技术最新进展。针对复杂地层钻井过程中遇到的高温高压高盐、泥页岩水化严重、井壁失稳、大温差、井漏、储层损害，以及钻井液维护自动化程度低等问题，国内外学者研发了抗高温高盐水基/油基钻井液、恒流变钻井液、抗超高温泡沫钻井液、环境友好型超低温钻井液、智能温压响应承压堵漏材料、可降解储层保护材料、钻井液在线监测与自动加料系统等关键材料、体系与装备。但随着地质、工程环境愈加复杂 ，钻井液材料仍面临抗超高温高盐、超长时间稳定、防塌固壁、恶性漏失以及钻井液性能自动化调控等重大技术瓶颈。为满足复杂地层钻探过程中钻井液性能需求 ，未来还需深入研究钻井液处理剂在极端条件下的起效/失效机理 ，钻井液处理剂在微观-介观-宏观等不同尺度下的构效关系变化及作用机制，建立安全高效的钻井液多功能一体化调控方法，构建智能钻井液理论与技术，为实现复杂地层安全高效经济环保钻井提供关键技术支撑。
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。
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(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2016, 33(6): 1-9.
doi: 10.3969/j.issn.1001-5620.2016.06.001
Abstract:
2016, 33(6): 45-50.
doi: 10.3969/j.issn.1001-5620.2016.06.008
Abstract:
2016, 33(6): 10-16.
doi: 10.3969/j.issn.1001-5620.2016.06.002
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:
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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CN 12-1486/TE
ISSN 1001-5620
