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3 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
5 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
6 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
7 A New Fracturing Fluid with Temperature Resistance of 230℃
8 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
9 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
10 Progress in Studying Cement Sheath Failure in Perforated Wells
2 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
3 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
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
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2026, 43(1): 1-8.
doi: 10.12358/j.issn.1001-5620.2026.01.001
Abstract:
In deepwater drilling, drilling fluids are affected by seawater, highly mineralized brine, and polyvalent metal ions. Conventional lubricants such as mineral oils, vegetable oils, and fatty acids often exhibit poor dispersion and incompatibility in high salinity environments,separating out as oily or cheese like pastes, which reduces or even eliminates the lubricating performance of the drilling fluid. Currently, there are limited efficient lubricants in China suitable for brine-based drilling fluids, making it difficult to meet the demands of deepwater operations.To address this issue, this study reviews and analyzes international research progress on high performance water-based drilling fluids and salt-resistant lubricants for deepwater drilling. Laboratory evaluations were conducted on six lubricants with different compositions. The results show that all of them suffer from poor compatibility and fail to meet the required lubrication coefficient standards in seawater-based fluids.Based on these findings, a high-efficiency lubricant suitable for brine drilling fluids was developed using long-chain modified fatty acid esters compounded with non-ionic surfactants. This lubricant demonstrates good compatibility with seawater and brine-based fluids, with no separation of oily or cheese-like substances. It can reduce the lubrication coefficient of seawater-based fluids prepared with inorganic and organic salts to below 0.10. After hot rolling at 185℃, no oily material separates on the surface of the slurry, and the lubricating performance remains stable. Additionally, the lubricant does not cause foaming, does not affect the rheological properties of the drilling fluid, is environmentally friendly, has low biotoxicity, and does not harm the marine environment.
In deepwater drilling, drilling fluids are affected by seawater, highly mineralized brine, and polyvalent metal ions. Conventional lubricants such as mineral oils, vegetable oils, and fatty acids often exhibit poor dispersion and incompatibility in high salinity environments,separating out as oily or cheese like pastes, which reduces or even eliminates the lubricating performance of the drilling fluid. Currently, there are limited efficient lubricants in China suitable for brine-based drilling fluids, making it difficult to meet the demands of deepwater operations.To address this issue, this study reviews and analyzes international research progress on high performance water-based drilling fluids and salt-resistant lubricants for deepwater drilling. Laboratory evaluations were conducted on six lubricants with different compositions. The results show that all of them suffer from poor compatibility and fail to meet the required lubrication coefficient standards in seawater-based fluids.Based on these findings, a high-efficiency lubricant suitable for brine drilling fluids was developed using long-chain modified fatty acid esters compounded with non-ionic surfactants. This lubricant demonstrates good compatibility with seawater and brine-based fluids, with no separation of oily or cheese-like substances. It can reduce the lubrication coefficient of seawater-based fluids prepared with inorganic and organic salts to below 0.10. After hot rolling at 185℃, no oily material separates on the surface of the slurry, and the lubricating performance remains stable. Additionally, the lubricant does not cause foaming, does not affect the rheological properties of the drilling fluid, is environmentally friendly, has low biotoxicity, and does not harm the marine environment.
2026, 43(1): 9-17.
doi: 10.12358/j.issn.1001-5620.2026.01.002
Abstract:
To reveal the mechanisms of borehole wall instability occurred in drilling the Maokou carbonate formation in southern Sichuan province, systematic testing and discrete element numerical simulation were conducted on the friction characteristics of the surfaces of the fractures in the formation. Field data analysis confirms that borehole wall instability mainly takes place in the broken rocks in the Maokou formation in which fractures are developed. When drilling into this formation, caving and sloughing of the formation rocks frequently take place and serious local wash-out leads to enlarged holes, posing a threat to safety of drilling operation. Experimental results show that in the limestones of the Maokou formation, the surfaces of the natural/artificial fractures have coefficients of friction (COFs) ranging in 0.691-0.743 and 0.501-0.588. After contacting with the drilling fluid, the mechanical strengths of the surfaces of the fractures are reduced and the surfaces are also lubricated by the fluid, the COFs of the surfaces of the fractures are reduced by 16.9%-31.8% in average. In high stress condition, the micro convex spots on the surfaces of the fractures become softened and damaged, the COFs of some filled fractures can be reduced to 0.2-0.3. Simulation using discrete element method of the borehole wall instability in the Maokou formation which contains complex structural faces shows that when the angle between the orientation of a fracture and the maximum horizontal principal stress is between 45° and 60°, the fracture around the wellbore is easiest to be activated; a decrease in the friction coefficient of the surfaces of the fracture significantly increases the risk of shear slip of the rocks, thereby inducing wellbore instability such as caving and sloughing of the borehole wall and hole enlargement. Based on the above understanding, for a carbonate rock formation with high matrix strength and plenty of natural fractures, it is necessary to accurately assess the friction strength of the natural fractures, and use anti-collapse drilling fluids with excellent plugging capacity to effectively plug the fractures, suppress their lubrication effects, and enhance the friction strength of the surfaces of the fractures, thereby ensuring borehole wall stability and drilling safety.
To reveal the mechanisms of borehole wall instability occurred in drilling the Maokou carbonate formation in southern Sichuan province, systematic testing and discrete element numerical simulation were conducted on the friction characteristics of the surfaces of the fractures in the formation. Field data analysis confirms that borehole wall instability mainly takes place in the broken rocks in the Maokou formation in which fractures are developed. When drilling into this formation, caving and sloughing of the formation rocks frequently take place and serious local wash-out leads to enlarged holes, posing a threat to safety of drilling operation. Experimental results show that in the limestones of the Maokou formation, the surfaces of the natural/artificial fractures have coefficients of friction (COFs) ranging in 0.691-0.743 and 0.501-0.588. After contacting with the drilling fluid, the mechanical strengths of the surfaces of the fractures are reduced and the surfaces are also lubricated by the fluid, the COFs of the surfaces of the fractures are reduced by 16.9%-31.8% in average. In high stress condition, the micro convex spots on the surfaces of the fractures become softened and damaged, the COFs of some filled fractures can be reduced to 0.2-0.3. Simulation using discrete element method of the borehole wall instability in the Maokou formation which contains complex structural faces shows that when the angle between the orientation of a fracture and the maximum horizontal principal stress is between 45° and 60°, the fracture around the wellbore is easiest to be activated; a decrease in the friction coefficient of the surfaces of the fracture significantly increases the risk of shear slip of the rocks, thereby inducing wellbore instability such as caving and sloughing of the borehole wall and hole enlargement. Based on the above understanding, for a carbonate rock formation with high matrix strength and plenty of natural fractures, it is necessary to accurately assess the friction strength of the natural fractures, and use anti-collapse drilling fluids with excellent plugging capacity to effectively plug the fractures, suppress their lubrication effects, and enhance the friction strength of the surfaces of the fractures, thereby ensuring borehole wall stability and drilling safety.
2026, 43(1): 18-27.
doi: 10.12358/j.issn.1001-5620.2026.01.003
Abstract:
Experimental devices currently in use for lost circulation control test have such shortages in simulating dynamic circulation and evaluating the performance of lost circulation slurries. To overcome these shortages, a multiparameter dynamic lost circulation control experimental device was developed which integrates heterogeneous tortuous fracture simulation, temperature-pressure coupling control and real-time monitor functions. This device consists of a temperature-pressure controlled reactor (0-150℃)/(0-25 MPa), a work fluid synthesis system, a circulation pump set and a data acquisition and control system. It can be used to reconstruct tortuous fractures with lengths of 50-60 cm, and simulate the alternate migration-plugging process of lost circulation materials under dynamic circulation conditions. Using prefabricated heterogeneous artificial cores and reticulate metal frameworks, experiments were conducted on controlling lost circulation in multiscale fractures and nested frameworks, and the synergistic mechanism of the particle-gel composite system was revealed. Experimental results show that the lost circulation control slurry formulated based on the D90 rule achieves a coordinated improvement of suspension stability and plugging capacity through the “coarse particle bridging-fine particle filling – gel gap plugging” process, with the pressure bearing capacity of the plugging layer being over 12 MPa. The curing of the preinjected gel can significantly shorten the circulation time: the time for plugging a single fracture is shortened to 4 min, a plugging efficiency of at least 45% higher than plugging with single-particle lost circulation slurries, and this time is further reduced to 2.7 min when metal frameworks are used. This study has verified the engineering applicability of time-sequential synergistic process of lost circulation control with composite slurries under dynamic circulation conditions, providing theoretical support for the prevention and control of lost circulation in fractured-vuggy formations.
Experimental devices currently in use for lost circulation control test have such shortages in simulating dynamic circulation and evaluating the performance of lost circulation slurries. To overcome these shortages, a multiparameter dynamic lost circulation control experimental device was developed which integrates heterogeneous tortuous fracture simulation, temperature-pressure coupling control and real-time monitor functions. This device consists of a temperature-pressure controlled reactor (0-150℃)/(0-25 MPa), a work fluid synthesis system, a circulation pump set and a data acquisition and control system. It can be used to reconstruct tortuous fractures with lengths of 50-60 cm, and simulate the alternate migration-plugging process of lost circulation materials under dynamic circulation conditions. Using prefabricated heterogeneous artificial cores and reticulate metal frameworks, experiments were conducted on controlling lost circulation in multiscale fractures and nested frameworks, and the synergistic mechanism of the particle-gel composite system was revealed. Experimental results show that the lost circulation control slurry formulated based on the D90 rule achieves a coordinated improvement of suspension stability and plugging capacity through the “coarse particle bridging-fine particle filling – gel gap plugging” process, with the pressure bearing capacity of the plugging layer being over 12 MPa. The curing of the preinjected gel can significantly shorten the circulation time: the time for plugging a single fracture is shortened to 4 min, a plugging efficiency of at least 45% higher than plugging with single-particle lost circulation slurries, and this time is further reduced to 2.7 min when metal frameworks are used. This study has verified the engineering applicability of time-sequential synergistic process of lost circulation control with composite slurries under dynamic circulation conditions, providing theoretical support for the prevention and control of lost circulation in fractured-vuggy formations.
2026, 43(1): 28-34.
doi: 10.12358/j.issn.1001-5620.2026.01.004
Abstract:
To address the challenge of drilling fluid rheology instability resulted from high-temperature degradation of conventional polymers, three polymers PAANVCL, PAADEAM and PAANIPAM, with different thermo-responsive groups, were synthesized via free-radical polymerization using thermo-responsive monomers, including N-vinyl caprolactam (NVCL), N,N-diethylacrylamide (DEAM) and N-isopropylacrylamide (NIPAM), and hydrophilic monomers, including acrylamide (AM) and sodium 2-acrylamido-2-methylpropylsulfonate (NaAMPS). The lower critical solution temperature (LCST) of the polymer solutions was determined by the turbidimetric method, the structural changes of the polymers before and after interaction with bentonite were characterized using Fourier transform infrared spectroscopy (FT-IR), and the interactions between the polymers with different thermo-responsive groups and bentonite were comparatively analyzed via X-ray diffraction (XRD), Zeta potential measurement and isothermal adsorption test. Additionally, the influence of thermo-responsive group types on the high-temperature rheology of the polymers in bentonite-based slurries was investigated. It was found that the LCST of the thermo-responsive polymer PAANVCL is as high as 85℃, and those of the polymers PAADEAM and PAANIPAM are 77℃ and 73℃, respectively. At room temperature and 90℃, PAANVCL exhibits the highest adsorption capacity on bentonite particles, followed by PAADEAM and PAANIPAM. After aging at 160℃ for 16 hours, the retention rate of the apparent viscosity (AV) of the PAANVCL-bentonite water-based drilling fluid is 81.13%, compared with 72.52% for the PAADEAM-bentonite drilling fluid and 69.44% for the PAANIPAM-bentonite drilling fluid. Furthermore, at temperatures between 100℃ and 160℃, the AV, plastic viscosity (PV) and yield point (YP) of the PAANVCL-bentonite drilling fluid fluctuate in ranges of less than 15%, demonstrating good high-temperature rheological stability. The types of the thermo-responsive groups exhibit significant impact on the interaction between polymers and bentonite; PAANVCL, a polymer with cyclic thermo-responsive groups, exhibits superior rheological stability in water-based drilling fluids.
To address the challenge of drilling fluid rheology instability resulted from high-temperature degradation of conventional polymers, three polymers PAANVCL, PAADEAM and PAANIPAM, with different thermo-responsive groups, were synthesized via free-radical polymerization using thermo-responsive monomers, including N-vinyl caprolactam (NVCL), N,N-diethylacrylamide (DEAM) and N-isopropylacrylamide (NIPAM), and hydrophilic monomers, including acrylamide (AM) and sodium 2-acrylamido-2-methylpropylsulfonate (NaAMPS). The lower critical solution temperature (LCST) of the polymer solutions was determined by the turbidimetric method, the structural changes of the polymers before and after interaction with bentonite were characterized using Fourier transform infrared spectroscopy (FT-IR), and the interactions between the polymers with different thermo-responsive groups and bentonite were comparatively analyzed via X-ray diffraction (XRD), Zeta potential measurement and isothermal adsorption test. Additionally, the influence of thermo-responsive group types on the high-temperature rheology of the polymers in bentonite-based slurries was investigated. It was found that the LCST of the thermo-responsive polymer PAANVCL is as high as 85℃, and those of the polymers PAADEAM and PAANIPAM are 77℃ and 73℃, respectively. At room temperature and 90℃, PAANVCL exhibits the highest adsorption capacity on bentonite particles, followed by PAADEAM and PAANIPAM. After aging at 160℃ for 16 hours, the retention rate of the apparent viscosity (AV) of the PAANVCL-bentonite water-based drilling fluid is 81.13%, compared with 72.52% for the PAADEAM-bentonite drilling fluid and 69.44% for the PAANIPAM-bentonite drilling fluid. Furthermore, at temperatures between 100℃ and 160℃, the AV, plastic viscosity (PV) and yield point (YP) of the PAANVCL-bentonite drilling fluid fluctuate in ranges of less than 15%, demonstrating good high-temperature rheological stability. The types of the thermo-responsive groups exhibit significant impact on the interaction between polymers and bentonite; PAANVCL, a polymer with cyclic thermo-responsive groups, exhibits superior rheological stability in water-based drilling fluids.
2026, 43(1): 35-40.
doi: 10.12358/j.issn.1001-5620.2026.01.005
Abstract:
The Shaximiao formation during drilling has found serious borehole wall collapse and the fallen debris were difficult to be brought out of the hole. To deal with this problem, an environmentally friendly drilling fluid suitable for drilling the Shaximiao formation in block Zhongjiang was selected and optimized for hole stabilization. The Shaximiao formation is developed with stack-structured fractures, and the bonding strengths between the clay minerals and the other minerals are low, thus, in the long-term exposure of the borehole walls into a water-based drilling fluid, it is easy to induce the propagation of the fractures in the formation to produce spalling and fallen debris, causing the borehole wall to collapse. The drilling fluid selected is an environmentally friendly biomass synthetic-based drilling fluid having good compatibility with the formation. Laboratory evaluation results showed that this drilling fluid has good inhibitive capacity, the 16 h linear expansion rate of rock cores tested with this drilling fluid is 0.62%, the permeability of the drilling fluid is low, and the wetting angle is 28.9°. This drilling fluid has the property of low viscosity and high gel strength, at 80℃-100℃ and 40 MPa, the YP/PV ratio is higher than 0.3 Pa/(mPa·s). The drilling fluid has stable properties at low temperature and high density. The PPA filtration rate of the drilling fluid tested on sand disks of different pore sizes is zero, and the penetration depths of the mud filtrates into visual sand-beds of different meshes are between 7 mm and 20 mm, indicating that the drilling fluid performs very well in plugging micropores and microfractures. Using this drilling fluid, borehole wall instability problem was solved, and all wells were successfully drilled to the designed depths with no downhole problems. The use of this drilling fluid provides an environmentally friendly technical guarantee for efficiently drilling the Shaximiao formation in the block Zhongjiang.
The Shaximiao formation during drilling has found serious borehole wall collapse and the fallen debris were difficult to be brought out of the hole. To deal with this problem, an environmentally friendly drilling fluid suitable for drilling the Shaximiao formation in block Zhongjiang was selected and optimized for hole stabilization. The Shaximiao formation is developed with stack-structured fractures, and the bonding strengths between the clay minerals and the other minerals are low, thus, in the long-term exposure of the borehole walls into a water-based drilling fluid, it is easy to induce the propagation of the fractures in the formation to produce spalling and fallen debris, causing the borehole wall to collapse. The drilling fluid selected is an environmentally friendly biomass synthetic-based drilling fluid having good compatibility with the formation. Laboratory evaluation results showed that this drilling fluid has good inhibitive capacity, the 16 h linear expansion rate of rock cores tested with this drilling fluid is 0.62%, the permeability of the drilling fluid is low, and the wetting angle is 28.9°. This drilling fluid has the property of low viscosity and high gel strength, at 80℃-100℃ and 40 MPa, the YP/PV ratio is higher than 0.3 Pa/(mPa·s). The drilling fluid has stable properties at low temperature and high density. The PPA filtration rate of the drilling fluid tested on sand disks of different pore sizes is zero, and the penetration depths of the mud filtrates into visual sand-beds of different meshes are between 7 mm and 20 mm, indicating that the drilling fluid performs very well in plugging micropores and microfractures. Using this drilling fluid, borehole wall instability problem was solved, and all wells were successfully drilled to the designed depths with no downhole problems. The use of this drilling fluid provides an environmentally friendly technical guarantee for efficiently drilling the Shaximiao formation in the block Zhongjiang.
2026, 43(1): 41-50.
doi: 10.12358/j.issn.1001-5620.2026.01.006
Abstract:
This study presents an idea of developing multifunctional drilling fluid additives to deal with the problems encountered in field drilling fluid engineering, such as too many kinds of drilling fluid additives, drilling fluid additives with their main function being prominent and secondary functions being unsatisfactory, as well as many drilling fluids with complex compositions, difficulties in property maintenance and poor compatibility among the additives. A multifunctional drilling fluid additive MPA-1 with three functions, which are filtration reduction, shale inhibition and lubricity improvement, was developed through L9(34) orthogonal experiment with which the monomers and their optimal concentrations, and the optimal reaction conditions were determined. The number average molecular weight and the weight average molecular weight of MPA-1 are 15.6×104 and 28.2×104, respectively. TGA results show that the initial decomposition temperature of the MPA-1 molecules is about 255℃. Compared with many other commonly used single-function additives, 1%MPA-1 in a 5% sodium bentonite slurry exhibits better performance in filtration control, lubrication and shale inhibition after the slurry is aged at 120℃ for 16 h. In 5% sodium bentonite slurry containing 5%-10%KCl, MPA-1 exhibits good salt resistance. When three samples of a potassium amine/potassium polymer sulfonate drilling fluid, which was used to drill 3 wells, were treated with 0.3%-0.5%MPA-1 and then allowed to age at 120℃ for 16 h, the viscosity of the samples increased moderately, the API filtration rate decreased significantly, and the lubricity of the mud cakes was improved. Replacing the 1%KPAM+1%Lube-3+1%SMJA-1 in the field potassium amine drilling fluid with 1.5%MPA-1, the composition of the drilling fluid was simplified, and the filtration rate, viscosity, viscosity coefficient of the drilling fluid, as well as the relative rate of expansion of bentonite pallets were wholly reduced. Mechanism analysis shows that the cationic groups in MPA-1 molecules moderately improve the hydrophobicity of clay particles by adsorbing on their surfaces, thereby inhibiting the clay particles and improving the lubricity of the drilling fluid at the same time. The anionic groups in the MPA-1 molecules, on the other hand, enter the hydration layer of clay particles, thereby enhancing the electronegativity of the clay particle surfaces, and increasing the thickness of the hydration films. These effects, together with the encapsulating effect of the main chains of the MPA-1 molecules, enlarge the range of the particle size distribution of the clay particles, which in turn helps produce thinner and denser mud cakes, reducing the filtration rate of the drilling fluid. The results of the research indicate that the multifunctional drilling fluid additive MPA-1 has the ability to reduce filtration rate, enhance lubricity and improve shale inhibition which satisfy the requirements of drilling a well with bottomhole temperatures less than 150℃, and this is beneficial to simplifying mud composition and reducing the difficulties in the maintenance and treatment of a drilling fluid in field operation.
This study presents an idea of developing multifunctional drilling fluid additives to deal with the problems encountered in field drilling fluid engineering, such as too many kinds of drilling fluid additives, drilling fluid additives with their main function being prominent and secondary functions being unsatisfactory, as well as many drilling fluids with complex compositions, difficulties in property maintenance and poor compatibility among the additives. A multifunctional drilling fluid additive MPA-1 with three functions, which are filtration reduction, shale inhibition and lubricity improvement, was developed through L9(34) orthogonal experiment with which the monomers and their optimal concentrations, and the optimal reaction conditions were determined. The number average molecular weight and the weight average molecular weight of MPA-1 are 15.6×104 and 28.2×104, respectively. TGA results show that the initial decomposition temperature of the MPA-1 molecules is about 255℃. Compared with many other commonly used single-function additives, 1%MPA-1 in a 5% sodium bentonite slurry exhibits better performance in filtration control, lubrication and shale inhibition after the slurry is aged at 120℃ for 16 h. In 5% sodium bentonite slurry containing 5%-10%KCl, MPA-1 exhibits good salt resistance. When three samples of a potassium amine/potassium polymer sulfonate drilling fluid, which was used to drill 3 wells, were treated with 0.3%-0.5%MPA-1 and then allowed to age at 120℃ for 16 h, the viscosity of the samples increased moderately, the API filtration rate decreased significantly, and the lubricity of the mud cakes was improved. Replacing the 1%KPAM+1%Lube-3+1%SMJA-1 in the field potassium amine drilling fluid with 1.5%MPA-1, the composition of the drilling fluid was simplified, and the filtration rate, viscosity, viscosity coefficient of the drilling fluid, as well as the relative rate of expansion of bentonite pallets were wholly reduced. Mechanism analysis shows that the cationic groups in MPA-1 molecules moderately improve the hydrophobicity of clay particles by adsorbing on their surfaces, thereby inhibiting the clay particles and improving the lubricity of the drilling fluid at the same time. The anionic groups in the MPA-1 molecules, on the other hand, enter the hydration layer of clay particles, thereby enhancing the electronegativity of the clay particle surfaces, and increasing the thickness of the hydration films. These effects, together with the encapsulating effect of the main chains of the MPA-1 molecules, enlarge the range of the particle size distribution of the clay particles, which in turn helps produce thinner and denser mud cakes, reducing the filtration rate of the drilling fluid. The results of the research indicate that the multifunctional drilling fluid additive MPA-1 has the ability to reduce filtration rate, enhance lubricity and improve shale inhibition which satisfy the requirements of drilling a well with bottomhole temperatures less than 150℃, and this is beneficial to simplifying mud composition and reducing the difficulties in the maintenance and treatment of a drilling fluid in field operation.
2026, 43(1): 51-56.
doi: 10.12358/j.issn.1001-5620.2026.01.007
Abstract:
High filtration rate lost circulation materials have several shortcomings such as inability to use at elevated temperatures, inability to mix with oil-based drilling fluids and low acid solubility etc. A high filtration rate lost circulation agent for use in oil-based drilling fluids have been developed to deal with these problems. This new lost circulation agent can be used at 150℃-190℃, and has acid solubility of 75.7%. It is composed mainly of a high softening point epoxy resin, a latent curing agent, and a highly acid soluble fiber, which has certain strength after filtering and piling. Laboratory evaluation experiment shows that this lost circulation agent can effectively consolidate after filtering, the plugging layer formed by the lost circulation agent after filtering has compressive strength that is greater than 4 MPa. The plugging layers formed in 1-5 mm fractures have compressive strengths that are greater than 11.5 MPa. The plugging layers do not cure at low temperatures and the curing time at elevated temperatures is 3.3-6.5 h, meaning that the use of this lost circulation agent is safe. A technology of using this lost circulation agent to formulate a high temperature high filtration rate acid soluble lost circulation slurry for use with oil-based drilling fluids has been used to control the loss of oil-based drilling fluid occurred on the well Yong-X. The operation temperature was 151℃, and the severe mud losses into the pay zones were successfully brought under control.
High filtration rate lost circulation materials have several shortcomings such as inability to use at elevated temperatures, inability to mix with oil-based drilling fluids and low acid solubility etc. A high filtration rate lost circulation agent for use in oil-based drilling fluids have been developed to deal with these problems. This new lost circulation agent can be used at 150℃-190℃, and has acid solubility of 75.7%. It is composed mainly of a high softening point epoxy resin, a latent curing agent, and a highly acid soluble fiber, which has certain strength after filtering and piling. Laboratory evaluation experiment shows that this lost circulation agent can effectively consolidate after filtering, the plugging layer formed by the lost circulation agent after filtering has compressive strength that is greater than 4 MPa. The plugging layers formed in 1-5 mm fractures have compressive strengths that are greater than 11.5 MPa. The plugging layers do not cure at low temperatures and the curing time at elevated temperatures is 3.3-6.5 h, meaning that the use of this lost circulation agent is safe. A technology of using this lost circulation agent to formulate a high temperature high filtration rate acid soluble lost circulation slurry for use with oil-based drilling fluids has been used to control the loss of oil-based drilling fluid occurred on the well Yong-X. The operation temperature was 151℃, and the severe mud losses into the pay zones were successfully brought under control.
2026, 43(1): 57-64.
doi: 10.12358/j.issn.1001-5620.2026.01.008
Abstract:
In cementing a gas well with CO2 contained in the reservoir, it is inevitable for the cement slurries to contact with the CO2. The length of the contact time will possibly affect the early hydration characteristics and the development of the microstructure of the cement slurries, and worse still is the negative effects of this contact on the quality of well cementing. In this study, the change patterns of the early hydration characteristics, the mechanical properties and the permeability of a cement slurry were systematically investigated by controlling the ventilation time of CO2. Using XRD, TG and SEM etc., the early phase composition and the evolution pattern of the cement slurry were analyzed. The study showed that the fluidity of the cement slurry was improved in the early stage and was then deteriorating with the time of CO2 ventilation. The setting time of the slurry, on the other hand, was shortened continuously. The hydration heat release curve showed that CO2 treatment significantly accelerated the cement hydration process, and increased the early cumulative released heat. However, as the time of CO2 ventilation increased, these effects became weakening. Compressive strength and permeability test results showed that CO2 treatment significantly enhanced the early strength of the cement slurry, and the best result can be obtained at ventilation time of less than 3 minutes. However, as the ventilation time of CO2 increased, the strength and permeability of the set cement both gradually decreased. XRD, TG and SEM analyses showed that CO2 treatment increased the formation of CaCO3, disrupted the coating structures formed by Ca(OH)2 and the C—S—H gel, and hence accelerated the hydration process of the cement particles.
In cementing a gas well with CO2 contained in the reservoir, it is inevitable for the cement slurries to contact with the CO2. The length of the contact time will possibly affect the early hydration characteristics and the development of the microstructure of the cement slurries, and worse still is the negative effects of this contact on the quality of well cementing. In this study, the change patterns of the early hydration characteristics, the mechanical properties and the permeability of a cement slurry were systematically investigated by controlling the ventilation time of CO2. Using XRD, TG and SEM etc., the early phase composition and the evolution pattern of the cement slurry were analyzed. The study showed that the fluidity of the cement slurry was improved in the early stage and was then deteriorating with the time of CO2 ventilation. The setting time of the slurry, on the other hand, was shortened continuously. The hydration heat release curve showed that CO2 treatment significantly accelerated the cement hydration process, and increased the early cumulative released heat. However, as the time of CO2 ventilation increased, these effects became weakening. Compressive strength and permeability test results showed that CO2 treatment significantly enhanced the early strength of the cement slurry, and the best result can be obtained at ventilation time of less than 3 minutes. However, as the ventilation time of CO2 increased, the strength and permeability of the set cement both gradually decreased. XRD, TG and SEM analyses showed that CO2 treatment increased the formation of CaCO3, disrupted the coating structures formed by Ca(OH)2 and the C—S—H gel, and hence accelerated the hydration process of the cement particles.
2026, 43(1): 65-72, 79.
doi: 10.12358/j.issn.1001-5620.2026.01.009
Abstract:
To improve the ability of set cement to resist carbonation-induced corrosion, the mobility, the strength of set cement and the depth of carbonation-induced corrosion in supercritical CO2 environment were measured of a cement slurry in which ultrafine slag was substituted for oil-well cement. This measurement was aimed to determine the appropriate amount of the slag to substitute cement. Using low-field NMR, XRD and SEM with energy dispersive spectroscopy, the mechanisms with which the substituting ultrafine slag affects the ability of the set cement to resist carbonation-induced corrosion was studied. It was concluded that when the substituting amount of the ultrafine slag is less than 40%, it helps improve the mobility of the cement slurry; when increasing the substituting amount of the ultrafine slag, the strength of the set cement first increases and then decreases, and the depths of the carbonation-induced corrosion first decrease and then increase. Compared with the reference sample, the cement slurry sample with substituting amount of 10% ultrafine slag has more gel pore developed while the number of capillary pores decreases. The cement slurry sample with substituting amount of more than 50% ultrafine slag has less gel pores and more capillary pores. The cement slurry sample with substituting amount of 30%-50% ultrafine slag has basically gel pores and no evident capillary pores. By associating the pore structure of the sample with the depth of the carbonation-induced corrosion, it was found that the sample containing substituting amount of 30%-50% ultrafine slag showed no significant corrosion, and this is relevant to the fact that it has no evident capillary pores. The sample containing substituting amount of 40% ultrafine slag has compact structure and no evident pores in the micromorphology. The hydration product of this sample is mainly fine fluffy-shaped CSH gel with low Ca/Si ratio, and contains less Ca(OH)2 mineral phase which is easily being corroded. Therefore, it is recommended that the appropriate substituting amount of ultrafine slag be around 40%.
To improve the ability of set cement to resist carbonation-induced corrosion, the mobility, the strength of set cement and the depth of carbonation-induced corrosion in supercritical CO2 environment were measured of a cement slurry in which ultrafine slag was substituted for oil-well cement. This measurement was aimed to determine the appropriate amount of the slag to substitute cement. Using low-field NMR, XRD and SEM with energy dispersive spectroscopy, the mechanisms with which the substituting ultrafine slag affects the ability of the set cement to resist carbonation-induced corrosion was studied. It was concluded that when the substituting amount of the ultrafine slag is less than 40%, it helps improve the mobility of the cement slurry; when increasing the substituting amount of the ultrafine slag, the strength of the set cement first increases and then decreases, and the depths of the carbonation-induced corrosion first decrease and then increase. Compared with the reference sample, the cement slurry sample with substituting amount of 10% ultrafine slag has more gel pore developed while the number of capillary pores decreases. The cement slurry sample with substituting amount of more than 50% ultrafine slag has less gel pores and more capillary pores. The cement slurry sample with substituting amount of 30%-50% ultrafine slag has basically gel pores and no evident capillary pores. By associating the pore structure of the sample with the depth of the carbonation-induced corrosion, it was found that the sample containing substituting amount of 30%-50% ultrafine slag showed no significant corrosion, and this is relevant to the fact that it has no evident capillary pores. The sample containing substituting amount of 40% ultrafine slag has compact structure and no evident pores in the micromorphology. The hydration product of this sample is mainly fine fluffy-shaped CSH gel with low Ca/Si ratio, and contains less Ca(OH)2 mineral phase which is easily being corroded. Therefore, it is recommended that the appropriate substituting amount of ultrafine slag be around 40%.
2026, 43(1): 73-79.
doi: 10.12358/j.issn.1001-5620.2026.01.010
Abstract:
To reduce the thermal resistance between the wellbore of a geothermal well and the rock formation and enhance the heat extraction capacity of the geothermal well, this paper selects graphite (SG) with excellent thermal conductivity as the heat-conducting material, and uses a surfactant to prepare a graphite dispersion. High aspect ratio carbon fibers (CF) are introduced to construct a heat-conducting network, which cooperatively improves the thermal conductivity of the cement paste. The performance of the graphite dispersion-cement slurry, as well as the mechanical and thermal conductivity properties of the cement paste, were evaluated. The phase composition, pore structure and microstructure of the cement paste were characterized by X-ray diffraction (XRD), thermogravimetric analysis (TG/DTG), mercury intrusion porosimetry (MIP) and scanning electron microscopy (SEM), and the thermal conduction mechanism was explored. The results show that when the W/S ratio is 0.51, the performance of the cement paste prepared by adding SG and CF meets the engineering requirements. The 24-hour compressive strength of the cement paste is not less than 17.0 MPa, the 7-day compressive strength is higher than 25.0 MPa, and its thermal conductivity can reach 2.86 W/(m·K). Under the combined effect of SG promoting hydration and CF inhibiting hydration, the weight loss of C—S—H and CH in the high-conductivity cement Ppaste was 10.91%, which was slightly lower than 11.04% of the pure cement paste. Appropriate SG can refine the pore size of the cement paste and reduce the porosity of the cement paste, while CF will significantly increase the porosity of the cement paste and increase the number of large pores. When the two are mixed, the porosity of the cement paste is 36.95%, which is higher than that of the pure cement paste. However, the number of pores larger than 70 nm in the high-conductivity cement paste is not much different from that of the pure cement paste. Adding SG and CF to the cement slurry can form a thermal conductivity network.
To reduce the thermal resistance between the wellbore of a geothermal well and the rock formation and enhance the heat extraction capacity of the geothermal well, this paper selects graphite (SG) with excellent thermal conductivity as the heat-conducting material, and uses a surfactant to prepare a graphite dispersion. High aspect ratio carbon fibers (CF) are introduced to construct a heat-conducting network, which cooperatively improves the thermal conductivity of the cement paste. The performance of the graphite dispersion-cement slurry, as well as the mechanical and thermal conductivity properties of the cement paste, were evaluated. The phase composition, pore structure and microstructure of the cement paste were characterized by X-ray diffraction (XRD), thermogravimetric analysis (TG/DTG), mercury intrusion porosimetry (MIP) and scanning electron microscopy (SEM), and the thermal conduction mechanism was explored. The results show that when the W/S ratio is 0.51, the performance of the cement paste prepared by adding SG and CF meets the engineering requirements. The 24-hour compressive strength of the cement paste is not less than 17.0 MPa, the 7-day compressive strength is higher than 25.0 MPa, and its thermal conductivity can reach 2.86 W/(m·K). Under the combined effect of SG promoting hydration and CF inhibiting hydration, the weight loss of C—S—H and CH in the high-conductivity cement Ppaste was 10.91%, which was slightly lower than 11.04% of the pure cement paste. Appropriate SG can refine the pore size of the cement paste and reduce the porosity of the cement paste, while CF will significantly increase the porosity of the cement paste and increase the number of large pores. When the two are mixed, the porosity of the cement paste is 36.95%, which is higher than that of the pure cement paste. However, the number of pores larger than 70 nm in the high-conductivity cement paste is not much different from that of the pure cement paste. Adding SG and CF to the cement slurry can form a thermal conductivity network.
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
摘要：
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
2016, 33(5): 1-8.
doi: 10.3969/j.issn.1001-5620.2016.05.001
摘要：
综述了国内外页岩气井井壁失稳机理、稳定井壁主要方法及水基钻井液技术研究与应用现状，讨论了当前中国页岩气井钻井液技术面临的主要技术难题，分析了美国页岩气井与中国主要页岩气产区井壁失稳机理的差异，指出了中国页岩气井水基钻井液技术研究存在的误区与不足，提出了中国页岩气井水基钻井液技术发展方向。
综述了国内外页岩气井井壁失稳机理、稳定井壁主要方法及水基钻井液技术研究与应用现状，讨论了当前中国页岩气井钻井液技术面临的主要技术难题，分析了美国页岩气井与中国主要页岩气产区井壁失稳机理的差异，指出了中国页岩气井水基钻井液技术研究存在的误区与不足，提出了中国页岩气井水基钻井液技术发展方向。
2016, 33(1): 33-36.
doi: 10.3969/j.issn.1001-5620.2016.01.007
摘要：
页岩具有极低的渗透率和极小的孔喉尺寸,传统封堵剂难以在页岩表面形成有效的泥饼,只有纳米级颗粒才能封堵页岩的孔喉,阻止液相侵入地层,维持井壁稳定,保护储层。以苯乙烯(St)、甲基丙烯酸甲酯(MMA)为单体,过硫酸钾(KPS)为引发剂,采用乳液聚合法制备了纳米聚合物微球封堵剂SD-seal。通过红外光谱、透射电镜、热重分析和激光粒度分析对产物进行了表征,通过龙马溪组岩样的压力传递实验研究了其封堵性能。结果表明,SD-seal纳米粒子分散性好,形状规则(基本为球形),粒度较均匀(20 nm左右),分解温度高达402.5℃,热稳定性好,阻缓压力传递效果显著,使龙马溪组页岩岩心渗透率降低95%。
页岩具有极低的渗透率和极小的孔喉尺寸,传统封堵剂难以在页岩表面形成有效的泥饼,只有纳米级颗粒才能封堵页岩的孔喉,阻止液相侵入地层,维持井壁稳定,保护储层。以苯乙烯(St)、甲基丙烯酸甲酯(MMA)为单体,过硫酸钾(KPS)为引发剂,采用乳液聚合法制备了纳米聚合物微球封堵剂SD-seal。通过红外光谱、透射电镜、热重分析和激光粒度分析对产物进行了表征,通过龙马溪组岩样的压力传递实验研究了其封堵性能。结果表明,SD-seal纳米粒子分散性好,形状规则(基本为球形),粒度较均匀(20 nm左右),分解温度高达402.5℃,热稳定性好,阻缓压力传递效果显著,使龙马溪组页岩岩心渗透率降低95%。
2018, 35(2): 1-16.
doi: 10.3969/j.issn.1001-5620.2018.02.001
摘要：
通常在勘探开发油气过程中会发生不同程度的油气层损害，导致产量下降、甚至"枪毙"油气层等，钻井液是第一个与油气层相接触的外来流体，引起的油气层损害程度往往较大。为减轻或避免钻井液导致的油气层损害、提高单井产量，国内外学者们进行了长达半个世纪以上的研究工作，先后建立了"屏蔽暂堵、精细暂堵、物理化学膜暂堵"三代暂堵型保护油气层钻井液技术，使保护油气层效果逐步提高，经济效益明显。但是，与石油工程师们追求的"超低"损害目标仍存在一定差距，特别是随着非常规、复杂、超深层、超深水等类型油气层勘探开发力度的加大，以前的保护技术难以满足要求。为此，将仿生学引入保护油气层钻井液理论中，发展了适合不同油气层渗透率大小的"超双疏、生物膜、协同增效"仿生技术，并在各大油田得到推广应用，达到了"超低"损害目标，标志着第四代暂堵型保护油气层钻井液技术的建立。对上述4代暂堵型保护油气层技术的理论基础、实施方案、室内评价、现场应用效果与优缺点等进行了论述，并通过梳理阐明了将来的研究方向与发展趋势，对现场技术人员和科技工作者具有较大指导意义。
通常在勘探开发油气过程中会发生不同程度的油气层损害，导致产量下降、甚至"枪毙"油气层等，钻井液是第一个与油气层相接触的外来流体，引起的油气层损害程度往往较大。为减轻或避免钻井液导致的油气层损害、提高单井产量，国内外学者们进行了长达半个世纪以上的研究工作，先后建立了"屏蔽暂堵、精细暂堵、物理化学膜暂堵"三代暂堵型保护油气层钻井液技术，使保护油气层效果逐步提高，经济效益明显。但是，与石油工程师们追求的"超低"损害目标仍存在一定差距，特别是随着非常规、复杂、超深层、超深水等类型油气层勘探开发力度的加大，以前的保护技术难以满足要求。为此，将仿生学引入保护油气层钻井液理论中，发展了适合不同油气层渗透率大小的"超双疏、生物膜、协同增效"仿生技术，并在各大油田得到推广应用，达到了"超低"损害目标，标志着第四代暂堵型保护油气层钻井液技术的建立。对上述4代暂堵型保护油气层技术的理论基础、实施方案、室内评价、现场应用效果与优缺点等进行了论述，并通过梳理阐明了将来的研究方向与发展趋势，对现场技术人员和科技工作者具有较大指导意义。
2016, 33(4): 74-78.
doi: 10.3969/j.issn.1001-5620.2016.04.015
摘要：
利用自主研发的水泥环密封性实验装置研究了套管内加卸压循环作用下水泥环的密封性，根据实验结果得出了循环应力作用下水泥环密封性失效的机理。实验结果显示，在较低套管内压循环作用下，水泥环保持密封性所能承受的应力循环次数较多；在较高循环应力作用下，水泥环密封性失效时循环次数较少。表明在套管内较低压力作用下，水泥环所受的应力较低，应力水平处于弹性状态，在加卸载的循环作用下，水泥环可随之弹性变形和弹性恢复；在较高应力作用下，水泥环内部固有的微裂纹和缺陷逐渐扩展和连通，除了发生弹性变形还产生了塑性变形；随着应力循环次数的增加，塑性变形也不断地累积。循环压力卸载时，套管弹性回缩而水泥环塑性变形不可完全恢复，2者在界面处的变形不协调而引起拉应力。当拉应力超过界面处的胶结强度时出现微环隙，导致水泥环密封性失效，水泥环发生循环应力作用的低周期密封性疲劳破坏。套管内压力越大，水泥环中产生的应力水平越高，产生的塑性变形越大，每次卸载时产生的残余应变和界面处拉应力也越大，因此引起密封性失效的应力循环次数越少。
利用自主研发的水泥环密封性实验装置研究了套管内加卸压循环作用下水泥环的密封性，根据实验结果得出了循环应力作用下水泥环密封性失效的机理。实验结果显示，在较低套管内压循环作用下，水泥环保持密封性所能承受的应力循环次数较多；在较高循环应力作用下，水泥环密封性失效时循环次数较少。表明在套管内较低压力作用下，水泥环所受的应力较低，应力水平处于弹性状态，在加卸载的循环作用下，水泥环可随之弹性变形和弹性恢复；在较高应力作用下，水泥环内部固有的微裂纹和缺陷逐渐扩展和连通，除了发生弹性变形还产生了塑性变形；随着应力循环次数的增加，塑性变形也不断地累积。循环压力卸载时，套管弹性回缩而水泥环塑性变形不可完全恢复，2者在界面处的变形不协调而引起拉应力。当拉应力超过界面处的胶结强度时出现微环隙，导致水泥环密封性失效，水泥环发生循环应力作用的低周期密封性疲劳破坏。套管内压力越大，水泥环中产生的应力水平越高，产生的塑性变形越大，每次卸载时产生的残余应变和界面处拉应力也越大，因此引起密封性失效的应力循环次数越少。
2017, 34(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2017.01.001
摘要：
分析了硬脆性泥页岩井壁失稳的原因，介绍了纳米材料特点及其应用，并概述了国内外钻井液用纳米封堵剂的研究进展，包括有机纳米封堵剂、无机纳米封堵剂、有机/无机纳米封堵剂，以及纳米封堵剂现场应用案例。笔者认为：利用无机纳米材料刚性特征以及有机聚合物可任意变形、支化成膜等特性，形成的一种核壳结构的无机/聚合物类纳米封堵剂，能够很好地分散到钻井液中，且对钻井液黏度和切力影响较小，这种类型的纳米封堵剂能够在低浓度下封堵泥页岩孔喉，建立一种疏水型且具有一定强度的泥页岩人工井壁，这不仅能够阻止钻井液侵入，而且还能提高地层承压能力，无机纳米材料与有机聚合物的结合是未来钻井液防塌剂的发展方向。
分析了硬脆性泥页岩井壁失稳的原因，介绍了纳米材料特点及其应用，并概述了国内外钻井液用纳米封堵剂的研究进展，包括有机纳米封堵剂、无机纳米封堵剂、有机/无机纳米封堵剂，以及纳米封堵剂现场应用案例。笔者认为：利用无机纳米材料刚性特征以及有机聚合物可任意变形、支化成膜等特性，形成的一种核壳结构的无机/聚合物类纳米封堵剂，能够很好地分散到钻井液中，且对钻井液黏度和切力影响较小，这种类型的纳米封堵剂能够在低浓度下封堵泥页岩孔喉，建立一种疏水型且具有一定强度的泥页岩人工井壁，这不仅能够阻止钻井液侵入，而且还能提高地层承压能力，无机纳米材料与有机聚合物的结合是未来钻井液防塌剂的发展方向。
2020, 37(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2020.01.001
摘要：
废弃钻井液污染大、种类多、处理难，给水质和土壤环境带来巨大的负面影响，随着近些年环保法规的日益完善，对废弃钻井液的处理技术也提出了新要求。概述了9种不同处理方法及其发展现状，重点分析了固化法、热解吸法、化学强化固液分离法、不落地技术和多种技术联用等处理技术，并对几种现行的主流处理技术进行了对比，指出了各类方法的发展前景，得出多种技术联用具有较好的发展潜力。分析认为今后的研究方向与热点在于如何低能耗、高效率地实现对废弃钻井液的资源化处理，具体工作既要包含污染物的源头、过程和结果控制，也要加强管理和相关制度的建立，综合开发新技术。
废弃钻井液污染大、种类多、处理难，给水质和土壤环境带来巨大的负面影响，随着近些年环保法规的日益完善，对废弃钻井液的处理技术也提出了新要求。概述了9种不同处理方法及其发展现状，重点分析了固化法、热解吸法、化学强化固液分离法、不落地技术和多种技术联用等处理技术，并对几种现行的主流处理技术进行了对比，指出了各类方法的发展前景，得出多种技术联用具有较好的发展潜力。分析认为今后的研究方向与热点在于如何低能耗、高效率地实现对废弃钻井液的资源化处理，具体工作既要包含污染物的源头、过程和结果控制，也要加强管理和相关制度的建立，综合开发新技术。
2016, 33(3): 25-29.
doi: 10.3969/j.issn.1001-5620.2016.03.005
摘要：
页岩气井水平井段井壁失稳是目前中国页岩气资源勘探开发的关键技术难题。通过云南昭通108区块龙马溪组页岩的X-射线衍射分析、扫描电镜（SEM）观察、力学特性分析、润湿性、膨胀率及回收率等实验，研究了其矿物组成、微观组构特征、表面性能、膨胀和分散特性，揭示了云南昭通108区块龙马溪组页岩地层井壁水化失稳机理。该地层黏土矿物以伊利石为主要组分，不含蒙脱石及伊蒙混层，表面水化是引起页岩地层井壁失稳的主要原因。基于热力学第二定律，利用降低页岩表面自由能以抑制页岩表面水化的原理，建立了通过多碳醇吸附作用改变页岩润湿性，有效降低其表面自由能、抑制表面水化，进而显著抑制页岩水化膨胀和分散的稳定井壁方法。
页岩气井水平井段井壁失稳是目前中国页岩气资源勘探开发的关键技术难题。通过云南昭通108区块龙马溪组页岩的X-射线衍射分析、扫描电镜（SEM）观察、力学特性分析、润湿性、膨胀率及回收率等实验，研究了其矿物组成、微观组构特征、表面性能、膨胀和分散特性，揭示了云南昭通108区块龙马溪组页岩地层井壁水化失稳机理。该地层黏土矿物以伊利石为主要组分，不含蒙脱石及伊蒙混层，表面水化是引起页岩地层井壁失稳的主要原因。基于热力学第二定律，利用降低页岩表面自由能以抑制页岩表面水化的原理，建立了通过多碳醇吸附作用改变页岩润湿性，有效降低其表面自由能、抑制表面水化，进而显著抑制页岩水化膨胀和分散的稳定井壁方法。
2016, 33(6): 121-126.
doi: 10.3969/j.issn.1001-5620.2016.06.022
摘要：
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现，存地液量越大，一年累积产量越高，与常规的返排率越高产量越高概念恰恰相反，可能与存地液的自发渗吸替油有关。核磁实验结果表明，渗吸替油不同于驱替作用，渗吸过程中小孔隙对采出程度贡献大，而驱替过程中大孔隙对采出程度贡献大，但从现场致密储层岩心孔隙度来看，储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素，探索影响压裂液油水置换的关键影响因素，得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明，各参数对渗吸速度的影响顺序为：界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大，渗吸采收率越大，但是增幅逐渐减小；原油黏度越小，渗吸采收率越大；渗吸液矿化度越大，渗吸采收率越大；当渗吸液中助排剂浓度在0.005%~5%，即界面张力在0.316~10.815 mN/m范围内时，浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明：并不是界面张力越低，采收率越高，而是存在某一最佳界面张力，使地层中被绕流油的数量减少，渗吸采收率达到最高，为油田提高致密储层采收率提供实验指导。
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现，存地液量越大，一年累积产量越高，与常规的返排率越高产量越高概念恰恰相反，可能与存地液的自发渗吸替油有关。核磁实验结果表明，渗吸替油不同于驱替作用，渗吸过程中小孔隙对采出程度贡献大，而驱替过程中大孔隙对采出程度贡献大，但从现场致密储层岩心孔隙度来看，储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素，探索影响压裂液油水置换的关键影响因素，得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明，各参数对渗吸速度的影响顺序为：界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大，渗吸采收率越大，但是增幅逐渐减小；原油黏度越小，渗吸采收率越大；渗吸液矿化度越大，渗吸采收率越大；当渗吸液中助排剂浓度在0.005%~5%，即界面张力在0.316~10.815 mN/m范围内时，浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明：并不是界面张力越低，采收率越高，而是存在某一最佳界面张力，使地层中被绕流油的数量减少，渗吸采收率达到最高，为油田提高致密储层采收率提供实验指导。
2018, 35(3): 8-16.
doi: 10.3969/j.issn.1001-5620.2018.03.002
摘要：
解决环境污染问题是改善钻井液的关键，开发环保型抗高温降滤失剂是当前研究的重要领域之一。概述了国内外环保型降滤失剂的研究进展，对国内外在环保型降滤失剂研制中所使用的原材料及产品性能，以及中国抗温改性天然高分子降滤失剂的发展近况进行了介绍。天然高分子降滤失剂是通过对淀粉、纤维素及木质素等天然高分子材料进行改性以提高其抗温、抗盐能力，使其可以应用于井温更高的深井钻探中。目前，中国环保型降滤失剂普遍可以应用到150℃的高温中，部分抗温能力可达到180℃却未能推广使用。通过对现有降滤失剂的研究，分析其抗高温的作用机理，探寻能有效提高抗温能力的单体分子结构及发挥作用的功能基团，例如磺酸基团、内酰胺基团等，以期对环保型抗高温降滤失剂的研制起到一定的指导和参考作用，加快环保型抗高温降滤失剂的发展。
解决环境污染问题是改善钻井液的关键，开发环保型抗高温降滤失剂是当前研究的重要领域之一。概述了国内外环保型降滤失剂的研究进展，对国内外在环保型降滤失剂研制中所使用的原材料及产品性能，以及中国抗温改性天然高分子降滤失剂的发展近况进行了介绍。天然高分子降滤失剂是通过对淀粉、纤维素及木质素等天然高分子材料进行改性以提高其抗温、抗盐能力，使其可以应用于井温更高的深井钻探中。目前，中国环保型降滤失剂普遍可以应用到150℃的高温中，部分抗温能力可达到180℃却未能推广使用。通过对现有降滤失剂的研究，分析其抗高温的作用机理，探寻能有效提高抗温能力的单体分子结构及发挥作用的功能基团，例如磺酸基团、内酰胺基团等，以期对环保型抗高温降滤失剂的研制起到一定的指导和参考作用，加快环保型抗高温降滤失剂的发展。
2020, 37(6): 685-693.
doi: 10.3969/j.issn.1001-5620.2020.06.002
Abstract:
2016, 33(5): 1-8.
doi: 10.3969/j.issn.1001-5620.2016.05.001
Abstract:
2016, 33(6): 1-9.
doi: 10.3969/j.issn.1001-5620.2016.06.001
Abstract:
2017, 34(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2017.01.001
Abstract:
2016, 33(6): 45-50.
doi: 10.3969/j.issn.1001-5620.2016.06.008
Abstract:
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2018, 35(1): 101-104.
doi: 10.3969/j.issn.1001-5620.2018.01.019
Abstract:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
Abstract:
2016, 33(6): 10-16.
doi: 10.3969/j.issn.1001-5620.2016.06.002
Abstract:
Governed by：
China National Petroleum Corporation Ltd
China National Petroleum Corporation Ltd
Sponsored by：
CNPC Bohai Drilling Engineering Co. Ltd
CNPC Bohai Drilling Engineering Co. Ltd
Editor-in-Chief：Shi-chun Chen（Engineer Technology Research Institute,BHDC）
Deputy Editor-in-chief：
Gui-juan Wang（Engineer Technology Research Institute,BHDC）Qiang Ren（Engineer Technology Research Institute,BHDC）
Address：
Room A517, China Petroleum Tianjin Building, No. 83, Second Avenue, Tianjin Economic and Technological Development Zone
Room A517, China Petroleum Tianjin Building, No. 83, Second Avenue, Tianjin Economic and Technological Development Zone
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E-mail： zjyywjy@126.com
CN 12-1486/TE
ISSN 1001-5620
