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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 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
10 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
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(4): 435-444.
doi: 10.12358/j.issn.1001-5620.2026.04.001
Abstract:
As oil and gas exploration gradually extends to deep and complex formation drilling as well as unconventional oil and gas reservoirs, drilling fluids in high temperature high pressure downhole environment are faced with dual severe challenges of wellbore instability and rapid deterioration of their own properties. Nano-silica (SiO2) exhibits great potential in enhancing the properties of a drilling fluid, its inherent agglomeration effect, however, restricts its application. To fully exert the nano-advantages of SiO2 and to endow it with specific functions, it is necessary to render surface modification to SiO2. This paper systematically reviews the mechanism and research progress of modified nano-SiO2 in drilling fluids, focusing on the multiple synergistical mechanisms of nano-SiO2 in physical plugging, chemical inhibition and interfacial regulation in wellbore stabilization. The application of modified nano-SiO2 as the core additive in optimizing drilling fluid rheology, controlling fluid loss and lubricating is also systematically summarized. The cutting-edge research advances of modified nano-SiO2-based smart responsive composite materials are comprehensively reviewed, and the huge potential of their smart behaviors, such as temperature responsiveness, in achieving formation-adaptative plugging and performance regulation are revealed. Although breakthroughs have been made currently in surface modification technology, property regulation mechanism and multifield applications of modified nano-SiO2, demonstrating broad industrialization prospects, bottlenecks still need to be urgently broken through in the mechanical and large-scale preparation as well as long-term stabilization of modified nano-SiO2 materials. Strength should be given in future research to solving the problems aforementioned to push forward the large-scale application of modified nano-SiO2 in drilling fluids.
As oil and gas exploration gradually extends to deep and complex formation drilling as well as unconventional oil and gas reservoirs, drilling fluids in high temperature high pressure downhole environment are faced with dual severe challenges of wellbore instability and rapid deterioration of their own properties. Nano-silica (SiO2) exhibits great potential in enhancing the properties of a drilling fluid, its inherent agglomeration effect, however, restricts its application. To fully exert the nano-advantages of SiO2 and to endow it with specific functions, it is necessary to render surface modification to SiO2. This paper systematically reviews the mechanism and research progress of modified nano-SiO2 in drilling fluids, focusing on the multiple synergistical mechanisms of nano-SiO2 in physical plugging, chemical inhibition and interfacial regulation in wellbore stabilization. The application of modified nano-SiO2 as the core additive in optimizing drilling fluid rheology, controlling fluid loss and lubricating is also systematically summarized. The cutting-edge research advances of modified nano-SiO2-based smart responsive composite materials are comprehensively reviewed, and the huge potential of their smart behaviors, such as temperature responsiveness, in achieving formation-adaptative plugging and performance regulation are revealed. Although breakthroughs have been made currently in surface modification technology, property regulation mechanism and multifield applications of modified nano-SiO2, demonstrating broad industrialization prospects, bottlenecks still need to be urgently broken through in the mechanical and large-scale preparation as well as long-term stabilization of modified nano-SiO2 materials. Strength should be given in future research to solving the problems aforementioned to push forward the large-scale application of modified nano-SiO2 in drilling fluids.
2026, 43(4): 445-451.
doi: 10.12358/j.issn.1001-5620.2026.04.002
Abstract:
Polymer filter loss reducers presently used in water-based drilling fluids have a problem of insufficient functional group density. To address this problem, a multifunction monomer A with hydroxyl and sulfonic acid group is used to replace the single-functional group monomer AMPS to react with AA, DMDAAC and polyether monomer H. The product of the free-radical copolymerization reaction is a quaterpolymer filter loss reducer. The ultra-high-temperature performance, salt-resistance, filtration control property and compatibility of this filter loss reducer was systematically investigated. The results show that after aging at 240 ℃ for 16 hours, a freshwater mud, a saltwater mud and a saturated saltwater mud, each containing 2% of the synthesized filter loss reducer, have API fluid losses that were reduced by 80%. Among these drilling fluids, the freshwater mud, which contains 2% of the filter loss reducer, still exhibits filtration control capacity even after being aged at 260 ℃. This filter loss reducer is excellently compatible with sulfonated lignite (SMC), and the use of the filter loss reducer with SMC makes the drilling fluid rheology easy to control; a drilling fluid treated with the filter loss reducer and SMC, after being aged at 240 ℃ for 16 hours, has an API filter loss of only 1.8 mL and an HTHP filter loss of only 24 mL. The research shows that the quaterpolymer filter loss reducer exhibits both excellent high-temperature stability and salt contamination resistant capacity, making it suitable for use in complex drilling conditions, such as drilling ultra-high-temperature formations and salt and gypsum formations. It provides a theoretical basis and technical support for the molecular design of ultra-high-temperature polymer filter loss reducer and the formulation of ultra-high-temperature saltwater-based drilling fluid system.
Polymer filter loss reducers presently used in water-based drilling fluids have a problem of insufficient functional group density. To address this problem, a multifunction monomer A with hydroxyl and sulfonic acid group is used to replace the single-functional group monomer AMPS to react with AA, DMDAAC and polyether monomer H. The product of the free-radical copolymerization reaction is a quaterpolymer filter loss reducer. The ultra-high-temperature performance, salt-resistance, filtration control property and compatibility of this filter loss reducer was systematically investigated. The results show that after aging at 240 ℃ for 16 hours, a freshwater mud, a saltwater mud and a saturated saltwater mud, each containing 2% of the synthesized filter loss reducer, have API fluid losses that were reduced by 80%. Among these drilling fluids, the freshwater mud, which contains 2% of the filter loss reducer, still exhibits filtration control capacity even after being aged at 260 ℃. This filter loss reducer is excellently compatible with sulfonated lignite (SMC), and the use of the filter loss reducer with SMC makes the drilling fluid rheology easy to control; a drilling fluid treated with the filter loss reducer and SMC, after being aged at 240 ℃ for 16 hours, has an API filter loss of only 1.8 mL and an HTHP filter loss of only 24 mL. The research shows that the quaterpolymer filter loss reducer exhibits both excellent high-temperature stability and salt contamination resistant capacity, making it suitable for use in complex drilling conditions, such as drilling ultra-high-temperature formations and salt and gypsum formations. It provides a theoretical basis and technical support for the molecular design of ultra-high-temperature polymer filter loss reducer and the formulation of ultra-high-temperature saltwater-based drilling fluid system.
2026, 43(4): 452-459.
doi: 10.12358/j.issn.1001-5620.2026.04.003
Abstract:
To improve the rheological performance of oil-based drilling fluids at high temperatures, bentonite was used as the matrix to comparatively investigate the effects of head-group structures, including quaternary ammonium, pyridine, and imidazole groups, and alkyl chain length on the microstructure and high-temperature rheological performance of organoclays. FT-IR, XRD, and thermogravimetric analyses showed that the modifiers were intercalated into the bentonite interlayers through electrostatic adsorption of the head groups and hydrophobic interactions among the tail chains, while some were physically adsorbed onto the surface. The maximum physical adsorption/electrostatic intercalation loadings of CTAC, OPB, CPB, OMB, and CMB on bentonite were 0.37/0.56 mmol/g, 0.021/0.63 mmol/g, 0.44/0.28 mmol/g, 0.016/0.54 mmol/g, and 0.17/0.48 mmol/g, respectively. Molecular dynamics simulations indicated that the absolute value of the electrostatic energy of CPB increased from 87.42 kcal/mol to 88.17 kcal/mol under high-temperature conditions, suggesting enhanced electrostatic interactions between CPB and bentonite. Rheological experiments showed that, with respect to head-group structures, heterocyclic-group-modified organoclays exhibited better high-temperature rheological performance, with the AV and YP of OBen-3 reaching 19 mPa·s and 3 Pa, respectively, after hot rolling at 240 ℃. As the alkyl chain length increased, the rheological performance of the organoclays improved markedly. After hot rolling at 240 ℃ in the all-oil-based drilling fluid system, OBen-3 exhibited AV, PV, and YP values of 90 mPa·s, 85 mPa·s, and 5 Pa, respectively, demonstrating good compatibility and high-temperature rheological performance. Moreover, the high-temperature and high-pressure filtration loss of OBen-3 was only 3.2 mL, indicating good filtration-loss control performance. In addition, OBen-3 exhibited favorable high-temperature rheological performance and effective high-temperature and high-pressure filtration-loss control in the water-in-oil system. This study suggests that introducing rigid structures with long alkyl chains can enhance intermolecular and interfacial interactions within the organoclay structure, thus significantly improving the high-temperature rheological performance of organoclays. These findings provide insights into the development of organoclays for high-temperature-resistant oil-based drilling fluids.
To improve the rheological performance of oil-based drilling fluids at high temperatures, bentonite was used as the matrix to comparatively investigate the effects of head-group structures, including quaternary ammonium, pyridine, and imidazole groups, and alkyl chain length on the microstructure and high-temperature rheological performance of organoclays. FT-IR, XRD, and thermogravimetric analyses showed that the modifiers were intercalated into the bentonite interlayers through electrostatic adsorption of the head groups and hydrophobic interactions among the tail chains, while some were physically adsorbed onto the surface. The maximum physical adsorption/electrostatic intercalation loadings of CTAC, OPB, CPB, OMB, and CMB on bentonite were 0.37/0.56 mmol/g, 0.021/0.63 mmol/g, 0.44/0.28 mmol/g, 0.016/0.54 mmol/g, and 0.17/0.48 mmol/g, respectively. Molecular dynamics simulations indicated that the absolute value of the electrostatic energy of CPB increased from 87.42 kcal/mol to 88.17 kcal/mol under high-temperature conditions, suggesting enhanced electrostatic interactions between CPB and bentonite. Rheological experiments showed that, with respect to head-group structures, heterocyclic-group-modified organoclays exhibited better high-temperature rheological performance, with the AV and YP of OBen-3 reaching 19 mPa·s and 3 Pa, respectively, after hot rolling at 240 ℃. As the alkyl chain length increased, the rheological performance of the organoclays improved markedly. After hot rolling at 240 ℃ in the all-oil-based drilling fluid system, OBen-3 exhibited AV, PV, and YP values of 90 mPa·s, 85 mPa·s, and 5 Pa, respectively, demonstrating good compatibility and high-temperature rheological performance. Moreover, the high-temperature and high-pressure filtration loss of OBen-3 was only 3.2 mL, indicating good filtration-loss control performance. In addition, OBen-3 exhibited favorable high-temperature rheological performance and effective high-temperature and high-pressure filtration-loss control in the water-in-oil system. This study suggests that introducing rigid structures with long alkyl chains can enhance intermolecular and interfacial interactions within the organoclay structure, thus significantly improving the high-temperature rheological performance of organoclays. These findings provide insights into the development of organoclays for high-temperature-resistant oil-based drilling fluids.
2026, 43(4): 460-469.
doi: 10.12358/j.issn.1001-5620.2026.04.004
Abstract:
To address the technical bottlenecks of difficult hole cleaning, high friction and torque, and poor wellbore stability in water-based drilling fluids during extended-reach well drilling, a high-performance brine-based drilling fluid system was developed. Based on a potassium chloride-formate composite brine, the system incorporated the self-developed star-shaped polyamine inhibitor HIB and nano-composite friction reducer SLIP, and optimized flow-pattern regulation and multi-stage plugging technologies, achieving synergistic improvements in inhibition, lubrication, cuttings-carrying capacity, and stability performance. Comprehensive comparisons with conventional KCl polymer systems, commercial polyamine systems, and lubricants showed that HIB exhibited significantly better inhibition than conventional polyamine inhibitors via an “adsorption–coating–hydrophobicity” mechanism, with a cuttings rolling recovery rate of 93.6% and a 16 h linear swelling rate of 1.0%. SLIP outperformed existing lubricants through a “microsphere rolling–adsorption film-forming” mechanism, with an extreme-pressure lubrication coefficient of 0.064 and an anti-wear load-bearing capacity of 10 kg. Laboratory evaluations showed that, after high-temperature aging at 150 ℃, the system maintained a yield point/plastic viscosity ratio of ≥0.5, an API filtration loss of <4 mL, a sand-bed pressure-bearing capacity of >7 MPa, strong contamination resistance, and a core permeability recovery value of >86.3%. Field applications in 12 extended-reach wells in several offshore blocks in China demonstrated that tripping friction was reduced by more than 30% and the rate of complex incidents decreased by 65%, providing a reliable technical option for the safe and efficient drilling of extended-reach wells.
To address the technical bottlenecks of difficult hole cleaning, high friction and torque, and poor wellbore stability in water-based drilling fluids during extended-reach well drilling, a high-performance brine-based drilling fluid system was developed. Based on a potassium chloride-formate composite brine, the system incorporated the self-developed star-shaped polyamine inhibitor HIB and nano-composite friction reducer SLIP, and optimized flow-pattern regulation and multi-stage plugging technologies, achieving synergistic improvements in inhibition, lubrication, cuttings-carrying capacity, and stability performance. Comprehensive comparisons with conventional KCl polymer systems, commercial polyamine systems, and lubricants showed that HIB exhibited significantly better inhibition than conventional polyamine inhibitors via an “adsorption–coating–hydrophobicity” mechanism, with a cuttings rolling recovery rate of 93.6% and a 16 h linear swelling rate of 1.0%. SLIP outperformed existing lubricants through a “microsphere rolling–adsorption film-forming” mechanism, with an extreme-pressure lubrication coefficient of 0.064 and an anti-wear load-bearing capacity of 10 kg. Laboratory evaluations showed that, after high-temperature aging at 150 ℃, the system maintained a yield point/plastic viscosity ratio of ≥0.5, an API filtration loss of <4 mL, a sand-bed pressure-bearing capacity of >7 MPa, strong contamination resistance, and a core permeability recovery value of >86.3%. Field applications in 12 extended-reach wells in several offshore blocks in China demonstrated that tripping friction was reduced by more than 30% and the rate of complex incidents decreased by 65%, providing a reliable technical option for the safe and efficient drilling of extended-reach wells.
2026, 43(4): 470-478.
doi: 10.12358/j.issn.1001-5620.2026.04.005
Abstract:
The tight sandstone reservoirs in a certain block of the Shengli Oilfield are characterized by high density and well-developed fractures, which make them highly susceptible to drilling fluid damage during drilling. Through evaluations of reservoir mineral composition, porosity and permeability characteristics, and sensitivities, the primary causes of reservoir damage were analyzed. Accordingly, this study developed a new temporary plugging agent capable of self-degradation at reservoir temperatures and constructed a low-damage water-based drilling fluid system. The results indicated that the reservoir faced damage from solid phase plugging of fractures, water blocking, water sensitivity, and acid sensitivity. The developed epoxy resin-based self-degradable temporary plugging agent underwent network depolymerization via ester bond hydrolysis and transesterification reactions at high temperatures, generating soluble oligomers. At a reservoir temperature of 120 ℃, its degradation rate reached 21.8% after 48 h and 96.4% after 96 h. In addition, its compressive strength significantly exceeded that of calcium carbonate, a commonly used temporary plugging agent. Performance evaluation experiments on the low-damage drilling fluid demonstrated that it possessed excellent properties in rheology, filtration control, lubricity, and clay hydration inhibition. Simulated fracture plugging and core permeability recovery experiments showed that solid phases, including the temporary plugging agent, rapidly formed a sealing layer within the fractures during drilling. This sealing layer maintained good pressure-bearing capacity even after standing for 48 h at 120 ℃. After standing for 48–72 h, the structure of the sealing layer broke down, and following a 24 h flowback period, the core permeability recovery exceeded 90%, namely that formation damage was avoided effectively. Field tests in three wells demonstrated that this drilling fluid exhibited excellent lost circulation prevention and control effects. Furthermore, it effectively protected the reservoir through the self-degradation of the temporary plugging agent, resulting in a 91.83% increase in crude oil production in comparison with offset wells. can undergo network depolymerization through ester bond hydrolysis at high temperatures, generating soluble oligomers. At the reservoir temperature of 120 ℃, its degradation rate reaches 21.8% after 48 hours and 96.4% after 96 hours, with compressive strength far exceeding that of calcium carbonate, which is the typical temporary plugging agent. Performance evaluation experiments of the low-damage drilling fluid show that it exhibits excellent rheological properties, filtration control, lubrication, and clay hydration inhibition. Simulated fracture plugging experiments and core permeability restoration tests demonstrate that solid-phase materials such as the temporary plugging agent rapidly form a plugging layer in fractures during drilling. After static placement at 120 ℃ for 48 hours, the plugging layer still maintains good pressure-bearing capacity. After 48 to 72 hours of static placement, the structure of the plugging layer breaks down, and the core permeability recovery value exceeds 90% after 24 hours of flowback, effectively avoiding reservoir damage. Field tests conducted on three wells indicate that the drilling fluid demonstrates excellent performance in leak prevention and plugging. Additionally, the self-degradation of the temporary plugging agent effectively protects the reservoir, resulting in a 91.83% increase in crude oil production compared to offset wells.
The tight sandstone reservoirs in a certain block of the Shengli Oilfield are characterized by high density and well-developed fractures, which make them highly susceptible to drilling fluid damage during drilling. Through evaluations of reservoir mineral composition, porosity and permeability characteristics, and sensitivities, the primary causes of reservoir damage were analyzed. Accordingly, this study developed a new temporary plugging agent capable of self-degradation at reservoir temperatures and constructed a low-damage water-based drilling fluid system. The results indicated that the reservoir faced damage from solid phase plugging of fractures, water blocking, water sensitivity, and acid sensitivity. The developed epoxy resin-based self-degradable temporary plugging agent underwent network depolymerization via ester bond hydrolysis and transesterification reactions at high temperatures, generating soluble oligomers. At a reservoir temperature of 120 ℃, its degradation rate reached 21.8% after 48 h and 96.4% after 96 h. In addition, its compressive strength significantly exceeded that of calcium carbonate, a commonly used temporary plugging agent. Performance evaluation experiments on the low-damage drilling fluid demonstrated that it possessed excellent properties in rheology, filtration control, lubricity, and clay hydration inhibition. Simulated fracture plugging and core permeability recovery experiments showed that solid phases, including the temporary plugging agent, rapidly formed a sealing layer within the fractures during drilling. This sealing layer maintained good pressure-bearing capacity even after standing for 48 h at 120 ℃. After standing for 48–72 h, the structure of the sealing layer broke down, and following a 24 h flowback period, the core permeability recovery exceeded 90%, namely that formation damage was avoided effectively. Field tests in three wells demonstrated that this drilling fluid exhibited excellent lost circulation prevention and control effects. Furthermore, it effectively protected the reservoir through the self-degradation of the temporary plugging agent, resulting in a 91.83% increase in crude oil production in comparison with offset wells. can undergo network depolymerization through ester bond hydrolysis at high temperatures, generating soluble oligomers. At the reservoir temperature of 120 ℃, its degradation rate reaches 21.8% after 48 hours and 96.4% after 96 hours, with compressive strength far exceeding that of calcium carbonate, which is the typical temporary plugging agent. Performance evaluation experiments of the low-damage drilling fluid show that it exhibits excellent rheological properties, filtration control, lubrication, and clay hydration inhibition. Simulated fracture plugging experiments and core permeability restoration tests demonstrate that solid-phase materials such as the temporary plugging agent rapidly form a plugging layer in fractures during drilling. After static placement at 120 ℃ for 48 hours, the plugging layer still maintains good pressure-bearing capacity. After 48 to 72 hours of static placement, the structure of the plugging layer breaks down, and the core permeability recovery value exceeds 90% after 24 hours of flowback, effectively avoiding reservoir damage. Field tests conducted on three wells indicate that the drilling fluid demonstrates excellent performance in leak prevention and plugging. Additionally, the self-degradation of the temporary plugging agent effectively protects the reservoir, resulting in a 91.83% increase in crude oil production compared to offset wells.
2026, 43(4): 479-488.
doi: 10.12358/j.issn.1001-5620.2026.04.006
Abstract:
Well Qiantan-1 is a wildcat well located at the Niudong structure in the Qaidam Basin. To address the wellbore instability challenge in the Jurassic formation it encountered, a systematic study was conducted, including geological characteristic characterization, instability mechanism analysis, development of plugging and anti-sloughing drilling fluid, and its field application, by comprehensively adopting methods such as core observation, scanning electron microscopy (SEM), mineral analysis, mechanical testing, numerical simulation and field tests. The results show that the dominant mechanism of wellbore instability in this formation is the mechanical sliding of high-steep fractures combined with spalling of hard and brittle rocks, with insufficient thermal stability and poor plugging and inhibition performance of drilling fluid being the key engineering inducing factors. The developed temperature-resistant, plugging and inhibition synergistic drilling fluid system realizes the performance indicators of HTHP fluid loss ≤12 mL, filter cake thickness ≤2 mm and core rolling recovery rate ≥98% at a high temperature of 180 ℃ through optimizing temperature-resistant materials, compounding multi-level plugging agents and strengthening the inhibition system. Field application of this system has reduced the occurrence rate of wellbore collapse in the fifth spud by 80%, increased the rate of penetration (ROP) by 52%, and controlled the wellbore enlargement rate within 8%. The established instability criteria and prevention & control technology for hard and brittle formations with high-steep fractures provide a theoretical basis and engineering example for drilling in similar formations, and possess important on-site guiding value.
Well Qiantan-1 is a wildcat well located at the Niudong structure in the Qaidam Basin. To address the wellbore instability challenge in the Jurassic formation it encountered, a systematic study was conducted, including geological characteristic characterization, instability mechanism analysis, development of plugging and anti-sloughing drilling fluid, and its field application, by comprehensively adopting methods such as core observation, scanning electron microscopy (SEM), mineral analysis, mechanical testing, numerical simulation and field tests. The results show that the dominant mechanism of wellbore instability in this formation is the mechanical sliding of high-steep fractures combined with spalling of hard and brittle rocks, with insufficient thermal stability and poor plugging and inhibition performance of drilling fluid being the key engineering inducing factors. The developed temperature-resistant, plugging and inhibition synergistic drilling fluid system realizes the performance indicators of HTHP fluid loss ≤12 mL, filter cake thickness ≤2 mm and core rolling recovery rate ≥98% at a high temperature of 180 ℃ through optimizing temperature-resistant materials, compounding multi-level plugging agents and strengthening the inhibition system. Field application of this system has reduced the occurrence rate of wellbore collapse in the fifth spud by 80%, increased the rate of penetration (ROP) by 52%, and controlled the wellbore enlargement rate within 8%. The established instability criteria and prevention & control technology for hard and brittle formations with high-steep fractures provide a theoretical basis and engineering example for drilling in similar formations, and possess important on-site guiding value.
2026, 43(4): 489-497.
doi: 10.12358/j.issn.1001-5620.2026.04.007
Abstract:
To address the persistent contamination of drilling fluids by CO2, the CO2 contamination to drilling fluids in the Penglai gas field in the Sichuan Basin is analyzed. In laboratory simulating experiment with high-temperature high-pressure (HTHP) CO2 contamination, the characteristics of persistent HTHP CO2 contamination was understood, and a set of measures for persistent CO2 contamination prevention and treatment was developed. The experimental results show that when persistent CO2 contamination is encountered, the concentrations of contaminant ions such as CO32− and HCO3− in the drilling fluid increase, and the pH of the drilling fluid decreases. This is due to the neutralization of CO2 by the caustic bases in the drilling fluid, instead of the dissolution and ionization of the CO2 molecules in water. In the treatment of a water-based drilling fluid, continual application of caustic soda results in continuous increase in the concentrations of CO32− and HCO3− in the drilling fluid. Bentonite platelets become fine particles under the action of CO32−/HCO3−, and the fine particles tend to aggregate due to CO32−/HCO3−-mediated dipole and hydrogen-bonding actions, thereby causing the drilling fluid to become viscosified. The synergy of a calcium additive and BK519 (a thinner) can be used to effectively prevent and deal with the persistent HTHP CO2 contamination. The achievement made in this research provides a theoretical and technical support to the in-depth revealing and effective preventing of persistent CO2 contamination encountered in deep formations.
To address the persistent contamination of drilling fluids by CO2, the CO2 contamination to drilling fluids in the Penglai gas field in the Sichuan Basin is analyzed. In laboratory simulating experiment with high-temperature high-pressure (HTHP) CO2 contamination, the characteristics of persistent HTHP CO2 contamination was understood, and a set of measures for persistent CO2 contamination prevention and treatment was developed. The experimental results show that when persistent CO2 contamination is encountered, the concentrations of contaminant ions such as CO32− and HCO3− in the drilling fluid increase, and the pH of the drilling fluid decreases. This is due to the neutralization of CO2 by the caustic bases in the drilling fluid, instead of the dissolution and ionization of the CO2 molecules in water. In the treatment of a water-based drilling fluid, continual application of caustic soda results in continuous increase in the concentrations of CO32− and HCO3− in the drilling fluid. Bentonite platelets become fine particles under the action of CO32−/HCO3−, and the fine particles tend to aggregate due to CO32−/HCO3−-mediated dipole and hydrogen-bonding actions, thereby causing the drilling fluid to become viscosified. The synergy of a calcium additive and BK519 (a thinner) can be used to effectively prevent and deal with the persistent HTHP CO2 contamination. The achievement made in this research provides a theoretical and technical support to the in-depth revealing and effective preventing of persistent CO2 contamination encountered in deep formations.
2026, 43(4): 498-505.
doi: 10.12358/j.issn.1001-5620.2026.04.008
Abstract:
Oil-based drilling fluids are commonly used in drilling deep and ultra-deep wells. However, in many drilling companies and many wells in northwest China, the service life of oil- and high-temperature-resistant positive-displacement-motors (PDM) used in oil-based drilling fluids varies erratically, in some cases, rubber detachment even occurs after only a dozen hours of operation. In laboratory experiment, two types of PDM stator rubbers with different crosslinking densities were soaked in different oil-based drilling fluids to test their rates of volume change and hardness change. The experiment was conducted at different temperatures with the stator rubbers and the oil-based drilling fluids collected from different drilling companies. The experimental results show that number 0 diesel oil exerts very slight effect on stator rubber, and the higher the crosslinking density, the stronger its resistance to medium-induced swelling. Oil-based drilling fluid components of the same commercial name but from different manufacturers differs to some extent in their effect on the hardness and rate of volume change of the PDM stator rubber. The main components of the oil-based drilling fluid from the drilling company X have minor effect on the stator rubber, while the secondary emulsifier and the wetting agent from the drilling company Y exert significant impact. After hot rolling at 180 ℃ for 48 hours in the emulsifier from the drilling company Y, the rubber B experienced a rate of volume change of 42.94% and Shore A hardness change of −17.2 HA. Meanwhile, after hot rolling under the same conditions in the wetting agent, the rubber B experienced a rate of volume change of 27.06% and Shore A hardness change of −9 HA. The aniline point and thermal weight loss of the main components of an oil-based drilling fluid cannot be used as technical parameters affecting the swelling of the stator rubber. The results of Fourier transform infrared spectroscopy (FT-IR) and gas chromatography-mass spectrometry (GC-MS) analyses demonstrate that the amide components in the secondary emulsifier and the wetting agent from the drilling company Y are the main factors causing volume change of the PDM stator rubber. After removing the amide components from the oil-based drilling fluid, the problem of rubber detachment from PDMs was effectively addressed.
Oil-based drilling fluids are commonly used in drilling deep and ultra-deep wells. However, in many drilling companies and many wells in northwest China, the service life of oil- and high-temperature-resistant positive-displacement-motors (PDM) used in oil-based drilling fluids varies erratically, in some cases, rubber detachment even occurs after only a dozen hours of operation. In laboratory experiment, two types of PDM stator rubbers with different crosslinking densities were soaked in different oil-based drilling fluids to test their rates of volume change and hardness change. The experiment was conducted at different temperatures with the stator rubbers and the oil-based drilling fluids collected from different drilling companies. The experimental results show that number 0 diesel oil exerts very slight effect on stator rubber, and the higher the crosslinking density, the stronger its resistance to medium-induced swelling. Oil-based drilling fluid components of the same commercial name but from different manufacturers differs to some extent in their effect on the hardness and rate of volume change of the PDM stator rubber. The main components of the oil-based drilling fluid from the drilling company X have minor effect on the stator rubber, while the secondary emulsifier and the wetting agent from the drilling company Y exert significant impact. After hot rolling at 180 ℃ for 48 hours in the emulsifier from the drilling company Y, the rubber B experienced a rate of volume change of 42.94% and Shore A hardness change of −17.2 HA. Meanwhile, after hot rolling under the same conditions in the wetting agent, the rubber B experienced a rate of volume change of 27.06% and Shore A hardness change of −9 HA. The aniline point and thermal weight loss of the main components of an oil-based drilling fluid cannot be used as technical parameters affecting the swelling of the stator rubber. The results of Fourier transform infrared spectroscopy (FT-IR) and gas chromatography-mass spectrometry (GC-MS) analyses demonstrate that the amide components in the secondary emulsifier and the wetting agent from the drilling company Y are the main factors causing volume change of the PDM stator rubber. After removing the amide components from the oil-based drilling fluid, the problem of rubber detachment from PDMs was effectively addressed.
2026, 43(4): 506-514.
doi: 10.12358/j.issn.1001-5620.2026.04.009
Abstract:
In the long-time service life of a cement sheath, micro-annuli and microfractures are easy to be generated therein due to the formation stress variations and the complex chemical environment, resulting in sustained casing pressure and loss of interlayer isolation. The use of hydrocarbon-triggered self-healing materials is an effective means of addressing this problem. Under an environment with both cement slurry and methane, a comparison was made of the expansion ratios by hydrocarbon absorption of a self-developed hydrocarbon-triggered self-healing material DBC-CA, namely, borate-crosslinked cyclodextrin-acrylate compounded resin, and a hydrogenated styrene-butadiene block copolymer (SEBS). The expansion mechanisms and thermal stability of these two hydrocarbon-triggered self-healing materials were investigated through 3D computed tomography (CT), scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR) and thermogravimetric analysis (TGA). The results of the research show that the expansion performance of DBC-CA in different environments is superior to that of SEBS, and DBC-CA also shows good thermal stability. In a methane environment, the highest expansion rate of DBC-CA is 37%, and DBC-CA is quite responsive to the environment, with its maximum expansion ratio in a cement slurry being less than 8%. A cement slurry containing 10% DBC-CA shows the best performance in minimizing the widths of the microfractures and in eliminating connected seepage channels. Morphological analysis demonstrates that the elastic energy dissipation characteristics of DBC-CA results from a triple protection mechanism involving rigid framework, dynamic bond rearrangement and nanocavities. DBC-CA can slightly reduce the 28-day compressive strength of a set cement. The achievements of this research provide a new idea for the design of downhole self-healing sealing materials for deep gas well application.
In the long-time service life of a cement sheath, micro-annuli and microfractures are easy to be generated therein due to the formation stress variations and the complex chemical environment, resulting in sustained casing pressure and loss of interlayer isolation. The use of hydrocarbon-triggered self-healing materials is an effective means of addressing this problem. Under an environment with both cement slurry and methane, a comparison was made of the expansion ratios by hydrocarbon absorption of a self-developed hydrocarbon-triggered self-healing material DBC-CA, namely, borate-crosslinked cyclodextrin-acrylate compounded resin, and a hydrogenated styrene-butadiene block copolymer (SEBS). The expansion mechanisms and thermal stability of these two hydrocarbon-triggered self-healing materials were investigated through 3D computed tomography (CT), scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR) and thermogravimetric analysis (TGA). The results of the research show that the expansion performance of DBC-CA in different environments is superior to that of SEBS, and DBC-CA also shows good thermal stability. In a methane environment, the highest expansion rate of DBC-CA is 37%, and DBC-CA is quite responsive to the environment, with its maximum expansion ratio in a cement slurry being less than 8%. A cement slurry containing 10% DBC-CA shows the best performance in minimizing the widths of the microfractures and in eliminating connected seepage channels. Morphological analysis demonstrates that the elastic energy dissipation characteristics of DBC-CA results from a triple protection mechanism involving rigid framework, dynamic bond rearrangement and nanocavities. DBC-CA can slightly reduce the 28-day compressive strength of a set cement. The achievements of this research provide a new idea for the design of downhole self-healing sealing materials for deep gas well application.
2026, 43(4): 515-521.
doi: 10.12358/j.issn.1001-5620.2026.04.010
Abstract:
Well cementing in the Chuanyu area (Sichuan and Chongqing) is faced with corrosion, deterioration and failure of sealing of cement sheath in acidic condition. To address these issues, a corrosion-resistant material DST with both filming adsorption and microstructure regulation and control functions was developed, and with DST, a low-permeability corrosion-resistant cement slurry was formulated. Different from conventional corrosion-resistant materials, DST can induce corrosive hydration products to transform from a loose structure to a dense spherical calcium carbonate packing, thereby blocking the deep penetration of the corrosive media. Based on the typical bottomhole temperature and pressure conditions (80 ℃/40 MPa), laboratory acid corrosion experiment and field application were conducted. The results show that after being corroded for 28 days, the compressive strength of the set cement is only reduced by 5%. The permeability of the set cement, although slightly increased, is finally lower than 4 × 10−5 μm2. The diameters of the main pores are kept at 10 – 90 nm, which are harmless or only slightly harmful, and no connected pores and loose structures are observed in the micromorphology of the set cement. This cement slurry has been applied in cementing a CCUS well in the Chuanyu area, and the first and the second bonding interfaces of the cement sheath are qualified at a rate exceeding 94%. In subsequent 300-day injection and production operations, no abnormal sustained pressure and CO2 leaking were monitored. The key corrosion-resistant material DST developed in this research and the low-permeability corrosion-resistant cement slurry significantly improve the long-term sealing of the CCUS wellbore and lay a solid foundation for cementing CO2 storage wells.
Well cementing in the Chuanyu area (Sichuan and Chongqing) is faced with corrosion, deterioration and failure of sealing of cement sheath in acidic condition. To address these issues, a corrosion-resistant material DST with both filming adsorption and microstructure regulation and control functions was developed, and with DST, a low-permeability corrosion-resistant cement slurry was formulated. Different from conventional corrosion-resistant materials, DST can induce corrosive hydration products to transform from a loose structure to a dense spherical calcium carbonate packing, thereby blocking the deep penetration of the corrosive media. Based on the typical bottomhole temperature and pressure conditions (80 ℃/40 MPa), laboratory acid corrosion experiment and field application were conducted. The results show that after being corroded for 28 days, the compressive strength of the set cement is only reduced by 5%. The permeability of the set cement, although slightly increased, is finally lower than 4 × 10−5 μm2. The diameters of the main pores are kept at 10 – 90 nm, which are harmless or only slightly harmful, and no connected pores and loose structures are observed in the micromorphology of the set cement. This cement slurry has been applied in cementing a CCUS well in the Chuanyu area, and the first and the second bonding interfaces of the cement sheath are qualified at a rate exceeding 94%. In subsequent 300-day injection and production operations, no abnormal sustained pressure and CO2 leaking were monitored. The key corrosion-resistant material DST developed in this research and the low-permeability corrosion-resistant cement slurry significantly improve the long-term sealing of the CCUS wellbore and lay a solid foundation for cementing CO2 storage wells.
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。
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。
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:
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:
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
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ISSN 1001-5620
