Submission & Review System
Search Article
Search Type
Search Journal
Download CenterMore
3 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
4 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
5 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
6 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
7 A New Fracturing Fluid with Temperature Resistance of 230℃
8 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
9 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
10 Progress in Studying Cement Sheath Failure in Perforated Wells
1 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
3 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
4 Challenges, Developments, and Suggestions for Drilling Fluid Technology in China
5 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
6 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
9 A New Fracturing Fluid with Temperature Resistance of 230℃
10 High Performance Water Base Drilling Fluid for Shale Gas Drilling
Articles in press have been peer-reviewed and accepted, which are not yet assigned to volumes /issues, but are citable by Digital Object Identifier (DOI).
Display Method:
Display Method:
2026, 43(3): 289-300.
doi: 10.12358/j.issn.1001-5620.2026.03.001
Abstract:
As oil and gas exploration extends to deep reservoirs, unconventional resources and other fields, formation conditions have become increasingly demanding. Operations such as well drilling, well completion, fracturing and acidizing are faced with greater challenges, imposing higher demands on oilfield chemical additives. As an efficient and smart means of material encapsulation and controlled release, microcapsule technology provides an important approach to the solution of technical challenges in oilfield chemistry. This paper systematically introduces key parameters of microcapsules such as their structural characteristics, particle size, micromorphology, encapsulation efficiency, and mechanical property etc., and discusses industrial production methods with promising application prospects and controllable costs. It focuses on reviewing the research and application advances of microcapsule technology in targeted lubrication of drilling and completion fluids, phase change temperature control, lost circulation prevention and control, self-healing of well cement sheath, corrosion inhibition, gel breaking of fracturing fluids, and sustained-release acidizing etc. Based on the current complex formation conditions, key problems of microcapsules are analyzed, such as insufficient stability, poor release controllability and difficulties in large-scale production. Directions of future development in microcapsule technology are prospected, including the design of high-performance wall-building materials, the development of multi-responsive microcapsules, the investigation of multi-factor release mechanisms, and low-cost green production processes. It is expected to provide references for the efficient, environmentally-friendly and intelligent development of oilfield chemical additives.
As oil and gas exploration extends to deep reservoirs, unconventional resources and other fields, formation conditions have become increasingly demanding. Operations such as well drilling, well completion, fracturing and acidizing are faced with greater challenges, imposing higher demands on oilfield chemical additives. As an efficient and smart means of material encapsulation and controlled release, microcapsule technology provides an important approach to the solution of technical challenges in oilfield chemistry. This paper systematically introduces key parameters of microcapsules such as their structural characteristics, particle size, micromorphology, encapsulation efficiency, and mechanical property etc., and discusses industrial production methods with promising application prospects and controllable costs. It focuses on reviewing the research and application advances of microcapsule technology in targeted lubrication of drilling and completion fluids, phase change temperature control, lost circulation prevention and control, self-healing of well cement sheath, corrosion inhibition, gel breaking of fracturing fluids, and sustained-release acidizing etc. Based on the current complex formation conditions, key problems of microcapsules are analyzed, such as insufficient stability, poor release controllability and difficulties in large-scale production. Directions of future development in microcapsule technology are prospected, including the design of high-performance wall-building materials, the development of multi-responsive microcapsules, the investigation of multi-factor release mechanisms, and low-cost green production processes. It is expected to provide references for the efficient, environmentally-friendly and intelligent development of oilfield chemical additives.
2026, 43(3): 301-309.
doi: 10.12358/j.issn.1001-5620.2026.03.002
Abstract:
Deep coalbed methane (CBM) has become an important part of unconventional natural gas resource development. CBM reservoirs are characteristic of strong heterogeneity, developed cleavage and microfractures, and low mechanical strength etc., which always result in problems such as borehole wall instability, difficulties in cuttings carrying and drilling fluid degassing, and serious reservoir damage etc. Key additives and high-performance drilling fluids for deep CBM development are in urgent need to ensure drilling with safety, high operational quality and high efficiency. This paper summarizes the progress made in recent years in the research of drilling fluid additives and systems for deep CBM development. Based on the effectiveness of the drilling fluid systems, the technical features of these drilling fluids are sorted and analyzed, the direction of future development of CBM drilling fluids is forecast, and these are of great importance to the high-quality high-efficiency deep CBM development, the high efficiency exploration and development of unconventional resources, and to the guarantee of national energy safety.
Deep coalbed methane (CBM) has become an important part of unconventional natural gas resource development. CBM reservoirs are characteristic of strong heterogeneity, developed cleavage and microfractures, and low mechanical strength etc., which always result in problems such as borehole wall instability, difficulties in cuttings carrying and drilling fluid degassing, and serious reservoir damage etc. Key additives and high-performance drilling fluids for deep CBM development are in urgent need to ensure drilling with safety, high operational quality and high efficiency. This paper summarizes the progress made in recent years in the research of drilling fluid additives and systems for deep CBM development. Based on the effectiveness of the drilling fluid systems, the technical features of these drilling fluids are sorted and analyzed, the direction of future development of CBM drilling fluids is forecast, and these are of great importance to the high-quality high-efficiency deep CBM development, the high efficiency exploration and development of unconventional resources, and to the guarantee of national energy safety.
2026, 43(3): 310-323.
doi: 10.12358/j.issn.1001-5620.2026.03.003
Abstract:
In recent years many studies have been conducted on near-oil-based drilling fluids to overcome the problems encountered in using oil-based drilling fluids such as high formulation cost and difficulties in addressing the oily cutting treatment problem. Based on the “near-oil-based” designing idea, a near-oil base fluid ZYBL was developed. ZYBL exhibits these features such as hydrophobicity through filming, water absorption through low water-activity reverse osmosis, ultra-strong inhibitive capacity and high lubricity etc. A near-oil-based drilling fluid was formulated with 20% ZYBL as the continuous phase and other additives of different functions such as rheology additives, filtration control agents, plugging agents, inhibitive agents and borehole wall strengthening agents. This near-oil-based drilling fluid has the working mechanism and properties that are similar to those of an oil-based drilling fluid, and is environmentally friendly. The density of this near-oil-based drilling fluid can be adjusted between 1.15 g/cm3 and 2.55 g/cm3. When the density of the drilling fluid is 1.15 g/cm3, the water activity is 0.651. This near-oil-based drilling fluid functions normally at temperatures up to 180 ℃ Laboratory experimental results show that the primary recovery rate of cuttings is 99.8%, the extreme-pressure coefficient of friction is 0.034, the mud cake adhesion coefficient is 0.0524, the API filtration rate is 0 mL, and the HTHP filtration rate is 6.6 mL. The near-oil-based drilling fluid exhibits good contamination resistance and reservoir protection capacity. An EC50 value of 139,700 mg/L means that it has no bio-toxicity. This near-oil-based drilling fluid in several aspects, such as shale inhibition, lubricity and reservoir protection etc., is similar to an oil-based drilling fluid. The cost of formulating this near-oil-based drilling fluid is significantly lower than that of formulating an oil-based drilling fluid. Field application of this near-oil-based drilling fluid on 55 wells in Xinjiang, Chuanyu, Zhongyuan oilfields and in northeast China has proven its advantages in borehole wall stabilization, lubrication, pipe sticking prevention, drilling rate enhancement, bottomhole temperature reduction through circulation, and low overall cost. Near-oil-based drilling fluid represents the mainstream development trend of water-based drilling fluids at home and abroad, it can be used in tough working conditions such as high-temperature deep and ultra-deep wells, long horizontal wells for shale oil and gas, and horizontal wells penetrating highly water-sensitive mudstones; it also enables green, safe, economical and efficient drilling, accelerates the achievement of the “replacing oil with water” technical goal, and delivers remarkable economic and social benefits with broad prospects for popularization and application.
In recent years many studies have been conducted on near-oil-based drilling fluids to overcome the problems encountered in using oil-based drilling fluids such as high formulation cost and difficulties in addressing the oily cutting treatment problem. Based on the “near-oil-based” designing idea, a near-oil base fluid ZYBL was developed. ZYBL exhibits these features such as hydrophobicity through filming, water absorption through low water-activity reverse osmosis, ultra-strong inhibitive capacity and high lubricity etc. A near-oil-based drilling fluid was formulated with 20% ZYBL as the continuous phase and other additives of different functions such as rheology additives, filtration control agents, plugging agents, inhibitive agents and borehole wall strengthening agents. This near-oil-based drilling fluid has the working mechanism and properties that are similar to those of an oil-based drilling fluid, and is environmentally friendly. The density of this near-oil-based drilling fluid can be adjusted between 1.15 g/cm3 and 2.55 g/cm3. When the density of the drilling fluid is 1.15 g/cm3, the water activity is 0.651. This near-oil-based drilling fluid functions normally at temperatures up to 180 ℃ Laboratory experimental results show that the primary recovery rate of cuttings is 99.8%, the extreme-pressure coefficient of friction is 0.034, the mud cake adhesion coefficient is 0.0524, the API filtration rate is 0 mL, and the HTHP filtration rate is 6.6 mL. The near-oil-based drilling fluid exhibits good contamination resistance and reservoir protection capacity. An EC50 value of 139,700 mg/L means that it has no bio-toxicity. This near-oil-based drilling fluid in several aspects, such as shale inhibition, lubricity and reservoir protection etc., is similar to an oil-based drilling fluid. The cost of formulating this near-oil-based drilling fluid is significantly lower than that of formulating an oil-based drilling fluid. Field application of this near-oil-based drilling fluid on 55 wells in Xinjiang, Chuanyu, Zhongyuan oilfields and in northeast China has proven its advantages in borehole wall stabilization, lubrication, pipe sticking prevention, drilling rate enhancement, bottomhole temperature reduction through circulation, and low overall cost. Near-oil-based drilling fluid represents the mainstream development trend of water-based drilling fluids at home and abroad, it can be used in tough working conditions such as high-temperature deep and ultra-deep wells, long horizontal wells for shale oil and gas, and horizontal wells penetrating highly water-sensitive mudstones; it also enables green, safe, economical and efficient drilling, accelerates the achievement of the “replacing oil with water” technical goal, and delivers remarkable economic and social benefits with broad prospects for popularization and application.
2026, 43(3): 324-330.
doi: 10.12358/j.issn.1001-5620.2026.03.004
Abstract:
A borehole wall stabilizer WDJ-1 was developed to address the problem of borehole wall instability and sloughing caused by property differences at the interface of coal-rock and coal-gangue in horizontal wells for deep coalbed methane (CBM). WDJ-1 was synthesized via aqueous solution polymerization using polyvinyl alcohol (PVA) and tannic acid (TA) as functional monomers, and borax and ferric chloride (FeCl3) as dual crosslinking agents. The synthesis was optimized with a monomer ratio of PVA∶TA = 1∶1, a reaction temperature of 85 ℃, a reaction time of 3 h, a system pH of 7.5, and the concentrations of the crosslinking agents (0.1% borax and 0.25% FeCl3). The structure of WDJ-1 was characterized by Fourier-transform infrared (FT-IR) spectroscopy, scanning electron microscopy (SEM), and thermogravimetric analysis (TGA), and its performance was evaluated through rheology, plugging capacity, cementation property, and inhibition property experiments. FT-IR confirms the presence of O—H, C=O, B—O, and Fe—O coordination bonds in the molecules of WDJ-1, indicating sufficient reaction between the monomers and the crosslinking agents. SEM reveals that WDJ-1 exhibits a honeycomb structure, which can improve the compactness of the mud cake. A base fluid treated with 2% WDJ-1 has its API fluid loss reduced from 22.4 mL to 3 mL, the shear strength of the coal rock-coal gangue interface reaches 0.16 MPa, the plugging pressure for a 2 mm slot plate increases by 54.5%, and the 48-hour water absorption rate of mud balls is reduced by 10.5%. TGA measurement proves that WDJ-1 exhibits excellent thermal stability below 240 ℃. WDJ-1 stabilizes wellbore through the four-fold synergistic mechanism of “inhibition-plugging-bonding-high temperature resistance”, and the use of which can provide technical support for the safe and efficient drilling of horizontal wells in deep CBM reservoirs.
A borehole wall stabilizer WDJ-1 was developed to address the problem of borehole wall instability and sloughing caused by property differences at the interface of coal-rock and coal-gangue in horizontal wells for deep coalbed methane (CBM). WDJ-1 was synthesized via aqueous solution polymerization using polyvinyl alcohol (PVA) and tannic acid (TA) as functional monomers, and borax and ferric chloride (FeCl3) as dual crosslinking agents. The synthesis was optimized with a monomer ratio of PVA∶TA = 1∶1, a reaction temperature of 85 ℃, a reaction time of 3 h, a system pH of 7.5, and the concentrations of the crosslinking agents (0.1% borax and 0.25% FeCl3). The structure of WDJ-1 was characterized by Fourier-transform infrared (FT-IR) spectroscopy, scanning electron microscopy (SEM), and thermogravimetric analysis (TGA), and its performance was evaluated through rheology, plugging capacity, cementation property, and inhibition property experiments. FT-IR confirms the presence of O—H, C=O, B—O, and Fe—O coordination bonds in the molecules of WDJ-1, indicating sufficient reaction between the monomers and the crosslinking agents. SEM reveals that WDJ-1 exhibits a honeycomb structure, which can improve the compactness of the mud cake. A base fluid treated with 2% WDJ-1 has its API fluid loss reduced from 22.4 mL to 3 mL, the shear strength of the coal rock-coal gangue interface reaches 0.16 MPa, the plugging pressure for a 2 mm slot plate increases by 54.5%, and the 48-hour water absorption rate of mud balls is reduced by 10.5%. TGA measurement proves that WDJ-1 exhibits excellent thermal stability below 240 ℃. WDJ-1 stabilizes wellbore through the four-fold synergistic mechanism of “inhibition-plugging-bonding-high temperature resistance”, and the use of which can provide technical support for the safe and efficient drilling of horizontal wells in deep CBM reservoirs.
2026, 43(3): 331-339.
doi: 10.12358/j.issn.1001-5620.2026.03.005
Abstract:
Lost circulation and wellbore instability have been encountered in drilling the Permian fractured formations in the sag west to the well Pen-1 in the Junggar Basin. To understand how oil-based/water-based drilling fluids affect the propagation pressure of a fracture, a comparative analysis was conducted on the effects of oil-based/water-based drilling fluids on the propagation pressure of the fracture. Physical simulation experiments on the propagation of core fractures were conducted through rock mechanical test, analysis of rock physical parameters as well as drilling fluid property test, and the law of the integrated action of the rock properties and drilling fluid properties on the propagation of fractures was systematically investigated. The conclusions of the experiments are as follows: ① fracturing the fractured cores with oil-based and water-based drilling fluids to observe the magnitude of the propagation pressure of the fractures, and it was found that the propagation pressure of the fractures measured in tests with oil-based drilling fluids is remarkably higher than that measured in tests with water-based drilling fluids. ② It was revealed that the drilling fluid viscosity is the primary factor controlling the propagation pressure of a fracture, and its importance exceeds the filtration property of the drilling fluid. High drilling fluid viscosity hinders the effective propagation of the pressure inside the fracture, hence significantly increasing the propagation pressure. ③ It was clarified that rock permeability is the prerequisite for the drilling fluid filtrates to form a “pressure drop zone” at the tip of a fracture and hence to promote the propagation. For oil-based drilling fluids, although having strong wetting capacity, their high viscosity and extremely low filtration rate work together to suppress the formation of the “pressure drop zone”, thereby masking the wettability potential. ④ Based on the experimental results, the contribution of each factor to fracture propagation pressure is quantified, the importance of these factors is listed as this: drilling fluid viscosity > rock permeability > filtration property > brittleness index > wettability > porosity. This research reveals the core mechanisms of oil-based and water-based drilling fluids in affecting the propagation pressure of a fracture, clarifies the key control factors and their relative importance, and provides an important theoretical support to the scientific selection of drilling fluid types and the formulation of control strategy for wellbore stability in safely drilling fractured formations.
Lost circulation and wellbore instability have been encountered in drilling the Permian fractured formations in the sag west to the well Pen-1 in the Junggar Basin. To understand how oil-based/water-based drilling fluids affect the propagation pressure of a fracture, a comparative analysis was conducted on the effects of oil-based/water-based drilling fluids on the propagation pressure of the fracture. Physical simulation experiments on the propagation of core fractures were conducted through rock mechanical test, analysis of rock physical parameters as well as drilling fluid property test, and the law of the integrated action of the rock properties and drilling fluid properties on the propagation of fractures was systematically investigated. The conclusions of the experiments are as follows: ① fracturing the fractured cores with oil-based and water-based drilling fluids to observe the magnitude of the propagation pressure of the fractures, and it was found that the propagation pressure of the fractures measured in tests with oil-based drilling fluids is remarkably higher than that measured in tests with water-based drilling fluids. ② It was revealed that the drilling fluid viscosity is the primary factor controlling the propagation pressure of a fracture, and its importance exceeds the filtration property of the drilling fluid. High drilling fluid viscosity hinders the effective propagation of the pressure inside the fracture, hence significantly increasing the propagation pressure. ③ It was clarified that rock permeability is the prerequisite for the drilling fluid filtrates to form a “pressure drop zone” at the tip of a fracture and hence to promote the propagation. For oil-based drilling fluids, although having strong wetting capacity, their high viscosity and extremely low filtration rate work together to suppress the formation of the “pressure drop zone”, thereby masking the wettability potential. ④ Based on the experimental results, the contribution of each factor to fracture propagation pressure is quantified, the importance of these factors is listed as this: drilling fluid viscosity > rock permeability > filtration property > brittleness index > wettability > porosity. This research reveals the core mechanisms of oil-based and water-based drilling fluids in affecting the propagation pressure of a fracture, clarifies the key control factors and their relative importance, and provides an important theoretical support to the scientific selection of drilling fluid types and the formulation of control strategy for wellbore stability in safely drilling fractured formations.
2026, 43(3): 340-348.
doi: 10.12358/j.issn.1001-5620.2026.03.006
Abstract:
In drilling fractured low-permeability reservoirs, bridging temporary plugging agent particles, because of their large sizes, are difficult to achieve tight plugging, and these particles exhibit low self-degradability. To address these technical challenges, a self-degradable bridging temporary plugging agent SMNP-1 was prepared via inverse microemulsion polymerization and using liquid microfluidics technology. The plugging agent SMNP-1 was synthesized using acrylamide (AM) and sodium p-styrenesulfonate (SSS) as the monomers, and β-cyclodextrin diacrylate ester (β-CD-AA) as the crosslinking agent. The molecular structure of SMNP-1 was verified with infrared spectrometer, and the particle size distribution and micromorphology of SMNP-1 were characterized with laser particle size analyzer and scanning electron microscope (SEM). Laboratory experiments were conducted to investigate SMNP-1 for its water absorption and swelling performance, adsorption performance, temporary plugging and unplugging performance, self-degradability, pressure-bearing capacity, and compatibility. Experimental results demonstrate that at elevated temperatures, SMNP-1 exhibits a moderate volumetric expansion rate after absorbing water, and a strong adsorption capacity. The SMNP-1 particles, after high-temperature treatment, show a normal size distribution and are morphologically nano-micron sized microspheres. At test temperatures of 100 ℃, 120 ℃, 140 ℃ and 160 ℃, the rates of SMNP-1 to plug natural cores are 96.88%, 96.63%, 96.57% and 95.27%, respectively. After 240 h of high temperature exposure, the unplugging rates of SMNP-1 are 87.22%, 89.95%, 93.27% and 96.13%, respectively, and the rates of self-degradation are 52.05%, 56.40%, 63.04% and 74.11%, respectively, demonstrating remarkable reservoir protection effect. At test temperature of 100 ℃, the maximum displacement pressure difference is 55 MPa, and a maximum displacement pressure difference of 25 MPa can still be achieved when the temperature is increased to 160 ℃, demonstrating an excellent plugging performance. SMNP-1 exhibits little effect on the rheology of drilling fluids, it can effectively enhance the wall-building capacity of a drilling fluid after fluid-loss and the reservoir protection effect. SMNP-1 has been successfully applied in the wild-cat well Xinsheng-1.
In drilling fractured low-permeability reservoirs, bridging temporary plugging agent particles, because of their large sizes, are difficult to achieve tight plugging, and these particles exhibit low self-degradability. To address these technical challenges, a self-degradable bridging temporary plugging agent SMNP-1 was prepared via inverse microemulsion polymerization and using liquid microfluidics technology. The plugging agent SMNP-1 was synthesized using acrylamide (AM) and sodium p-styrenesulfonate (SSS) as the monomers, and β-cyclodextrin diacrylate ester (β-CD-AA) as the crosslinking agent. The molecular structure of SMNP-1 was verified with infrared spectrometer, and the particle size distribution and micromorphology of SMNP-1 were characterized with laser particle size analyzer and scanning electron microscope (SEM). Laboratory experiments were conducted to investigate SMNP-1 for its water absorption and swelling performance, adsorption performance, temporary plugging and unplugging performance, self-degradability, pressure-bearing capacity, and compatibility. Experimental results demonstrate that at elevated temperatures, SMNP-1 exhibits a moderate volumetric expansion rate after absorbing water, and a strong adsorption capacity. The SMNP-1 particles, after high-temperature treatment, show a normal size distribution and are morphologically nano-micron sized microspheres. At test temperatures of 100 ℃, 120 ℃, 140 ℃ and 160 ℃, the rates of SMNP-1 to plug natural cores are 96.88%, 96.63%, 96.57% and 95.27%, respectively. After 240 h of high temperature exposure, the unplugging rates of SMNP-1 are 87.22%, 89.95%, 93.27% and 96.13%, respectively, and the rates of self-degradation are 52.05%, 56.40%, 63.04% and 74.11%, respectively, demonstrating remarkable reservoir protection effect. At test temperature of 100 ℃, the maximum displacement pressure difference is 55 MPa, and a maximum displacement pressure difference of 25 MPa can still be achieved when the temperature is increased to 160 ℃, demonstrating an excellent plugging performance. SMNP-1 exhibits little effect on the rheology of drilling fluids, it can effectively enhance the wall-building capacity of a drilling fluid after fluid-loss and the reservoir protection effect. SMNP-1 has been successfully applied in the wild-cat well Xinsheng-1.
2026, 43(3): 349-356.
doi: 10.12358/j.issn.1001-5620.2026.03.007
Abstract:
Conventional temporary plugging agents often cause secondary formation damage such as blocking of pore throats in reservoir formations and reduced permeability etc. due to incomplete gel-breaking, delayed unplugging or residues that are difficult to remove, severely restricting the recovery enhancement of oil and gas reservoirs. Developing novel temporary plugging materials with both efficient plugging capacity and self-unplugging capability has become a core research direction and a new idea for technical breakthroughs in the field of oil and gas reservoir protection. Based on the Stöber method, a core-shell self-unplugging temporary plugging agent for drilling fluids was successfully developed using modified poly(butylene adipate-co-terephthalate) as the core and silica as the shell. With core-shell synergistical mechanism, the core of this temporary plugging agent ensures plugging strength, while the shell, with its smart responsive groups, achieves the goal of “strong plugging in the early stage and fast unplugging in the later stage”, thus resolving the contradiction of plugging and unplugging. The chemical structure, micromorphology and thermal stability of this temporary plugging agent was systematically characterized using Fourier transform infrared (FT-IR) spectroscopy, field emission scanning electron microscopy (FE-SEM) and simultaneous thermogravimetric-differential thermal analysis (TG-DTA). The results of the characterization show that the temporary plugging agent developed has an obvious core-shell structure. At 120 ℃ and a salinity of 150,000 mg/L, the rate of degradation of the temporary plugging agent reaches 33.62% in 15 days, and it is completely degraded in 36 days, which can meet the requirements of medium- and long-term safe operation. Meanwhile, the temporary plugging agent is well compatible with drilling fluids, it functions normally at temperatures up to 130 ℃, and is resistant to 25% NaCl environment. Plugging capacity test results show that the plugging depth of sand-bed reduced from 8.5 cm to 1.3 cm as the amount of the temporary plugging agent increases, the plugging efficiency reaches 89.32%, and the percent recovery of permeability is 95.45%, demonstrating both excellent plugging capacity and reservoir protection performance.
Conventional temporary plugging agents often cause secondary formation damage such as blocking of pore throats in reservoir formations and reduced permeability etc. due to incomplete gel-breaking, delayed unplugging or residues that are difficult to remove, severely restricting the recovery enhancement of oil and gas reservoirs. Developing novel temporary plugging materials with both efficient plugging capacity and self-unplugging capability has become a core research direction and a new idea for technical breakthroughs in the field of oil and gas reservoir protection. Based on the Stöber method, a core-shell self-unplugging temporary plugging agent for drilling fluids was successfully developed using modified poly(butylene adipate-co-terephthalate) as the core and silica as the shell. With core-shell synergistical mechanism, the core of this temporary plugging agent ensures plugging strength, while the shell, with its smart responsive groups, achieves the goal of “strong plugging in the early stage and fast unplugging in the later stage”, thus resolving the contradiction of plugging and unplugging. The chemical structure, micromorphology and thermal stability of this temporary plugging agent was systematically characterized using Fourier transform infrared (FT-IR) spectroscopy, field emission scanning electron microscopy (FE-SEM) and simultaneous thermogravimetric-differential thermal analysis (TG-DTA). The results of the characterization show that the temporary plugging agent developed has an obvious core-shell structure. At 120 ℃ and a salinity of 150,000 mg/L, the rate of degradation of the temporary plugging agent reaches 33.62% in 15 days, and it is completely degraded in 36 days, which can meet the requirements of medium- and long-term safe operation. Meanwhile, the temporary plugging agent is well compatible with drilling fluids, it functions normally at temperatures up to 130 ℃, and is resistant to 25% NaCl environment. Plugging capacity test results show that the plugging depth of sand-bed reduced from 8.5 cm to 1.3 cm as the amount of the temporary plugging agent increases, the plugging efficiency reaches 89.32%, and the percent recovery of permeability is 95.45%, demonstrating both excellent plugging capacity and reservoir protection performance.
2026, 43(3): 357-365.
doi: 10.12358/j.issn.1001-5620.2026.03.008
Abstract:
When drilling low-temperature geothermal wells into high-pressure formations, the barite (BaSO4) in weighted drilling fluids, under the action of differential pressure, invade formation fractures and form insoluble filter cakes to block flow channels, causing production capacity to reduce. Regular acid job measures cannot be used to effectively dissolve barite, thus chelating blocking removing agents composed mainly of aminopolycarboxylates (such as diethylene triamine pentaacetate, DTPA) become a potential solution. Using DTPA as the main agent, the effects of reaction temperature, concentration of the main agent, bioenzyme (α-amylase) and basic conversion agent (K2CO3) on barite dissolution were systematically investigated. The performance of the blocking removing agent was evaluated through filter cake dissolution test and scanning electron microscopy (SEM), and the working mechanism was revealed. The results show that: (1) the dissolution capacity of DTPA solution for barite increases with increase in temperature. At 65 ℃, the optimum concentration of DTPA is 15%; adding 0.5% α-amylase and 4% K2CO3 on this basis can synergistically improve the dissolution effect, and an optimum blocking removing formula (15% DTPA + 0.5% α-amylase + 4% K2CO3) was then obtained, with barite dissolution capacity of 35.3 g/L. (2) The results of SEM analyses demonstrate that the barite particles after treatment exhibit porous and fracturing morphology, with roughness significantly increased. Filter cake dissolution experiment confirms that this blocking removing agent can efficiently penetrate into, dissolve and disperse barite filter cakes. Mechanism studies reveal that DTPA dissolves barite synergistically by inducing lattice distortion and chelating. (3) An index of “solute ratio” is presented to characterize the efficiency of removing barite from the borehole wall. The solute ratios in different boreholes are all greater than 1, indicating that the blocking removing agent can effectively remove filter cake attached to the borehole walls in a single treatment. The achievements made in this research provide a technical reference for reservoir protection in low-temperature geothermal well drilling.
When drilling low-temperature geothermal wells into high-pressure formations, the barite (BaSO4) in weighted drilling fluids, under the action of differential pressure, invade formation fractures and form insoluble filter cakes to block flow channels, causing production capacity to reduce. Regular acid job measures cannot be used to effectively dissolve barite, thus chelating blocking removing agents composed mainly of aminopolycarboxylates (such as diethylene triamine pentaacetate, DTPA) become a potential solution. Using DTPA as the main agent, the effects of reaction temperature, concentration of the main agent, bioenzyme (α-amylase) and basic conversion agent (K2CO3) on barite dissolution were systematically investigated. The performance of the blocking removing agent was evaluated through filter cake dissolution test and scanning electron microscopy (SEM), and the working mechanism was revealed. The results show that: (1) the dissolution capacity of DTPA solution for barite increases with increase in temperature. At 65 ℃, the optimum concentration of DTPA is 15%; adding 0.5% α-amylase and 4% K2CO3 on this basis can synergistically improve the dissolution effect, and an optimum blocking removing formula (15% DTPA + 0.5% α-amylase + 4% K2CO3) was then obtained, with barite dissolution capacity of 35.3 g/L. (2) The results of SEM analyses demonstrate that the barite particles after treatment exhibit porous and fracturing morphology, with roughness significantly increased. Filter cake dissolution experiment confirms that this blocking removing agent can efficiently penetrate into, dissolve and disperse barite filter cakes. Mechanism studies reveal that DTPA dissolves barite synergistically by inducing lattice distortion and chelating. (3) An index of “solute ratio” is presented to characterize the efficiency of removing barite from the borehole wall. The solute ratios in different boreholes are all greater than 1, indicating that the blocking removing agent can effectively remove filter cake attached to the borehole walls in a single treatment. The achievements made in this research provide a technical reference for reservoir protection in low-temperature geothermal well drilling.
2026, 43(3): 366-373.
doi: 10.12358/j.issn.1001-5620.2026.03.009
Abstract:
In deep and ultra-deep well drilling, after long period of circulation at ultra-high temperatures, oil-based drilling fluids will experience rheology deterioration problems, such as gel or suspending capacity decline, a causative factor for barite sag, stuck pipe and wellbore collapse etc. To deal with this problem, an ultra-high temperature amphiphilic oligomer flow pattern modifier was developed through high temperature amidation reaction with raw materials such as tall oil fatty acids, fatty alkyl polyamines and maleic anhydride. Laboratory experiments were conducted to carefully investigate the performance and mechanisms of the oligomer flow pattern modifier, and the experimental results show that the oligomer flow pattern modifier can be used to significantly improve the rheology and settling stability of oil-based drilling fluids. At 230 ℃, 0.5% oligomer flow pattern modifier can increase the yield value of a water-in-oil emulsion from 0.5 Pa to 4.5 Pa, and the emulsion stability voltage from 323 V to 509 V. It can increase the yield value of an oil-based drilling fluid from 6.5 Pa to 22.5 Pa, and the emulsion stability voltage from 1,014 V to 1,315 V. A mud sample was taken from a well, it was first hot rolled for 1 d, and then allowed for standing for 5 d. The mud sample was then treated with the oligomer flow pattern modifier, and it still acquired good gel strengths, settling stability and emulsion stability. This oligomer flow pattern modifier provides a technical reference for the development of ultra-high temperature oil-based drilling fluid.
In deep and ultra-deep well drilling, after long period of circulation at ultra-high temperatures, oil-based drilling fluids will experience rheology deterioration problems, such as gel or suspending capacity decline, a causative factor for barite sag, stuck pipe and wellbore collapse etc. To deal with this problem, an ultra-high temperature amphiphilic oligomer flow pattern modifier was developed through high temperature amidation reaction with raw materials such as tall oil fatty acids, fatty alkyl polyamines and maleic anhydride. Laboratory experiments were conducted to carefully investigate the performance and mechanisms of the oligomer flow pattern modifier, and the experimental results show that the oligomer flow pattern modifier can be used to significantly improve the rheology and settling stability of oil-based drilling fluids. At 230 ℃, 0.5% oligomer flow pattern modifier can increase the yield value of a water-in-oil emulsion from 0.5 Pa to 4.5 Pa, and the emulsion stability voltage from 323 V to 509 V. It can increase the yield value of an oil-based drilling fluid from 6.5 Pa to 22.5 Pa, and the emulsion stability voltage from 1,014 V to 1,315 V. A mud sample was taken from a well, it was first hot rolled for 1 d, and then allowed for standing for 5 d. The mud sample was then treated with the oligomer flow pattern modifier, and it still acquired good gel strengths, settling stability and emulsion stability. This oligomer flow pattern modifier provides a technical reference for the development of ultra-high temperature oil-based drilling fluid.
2026, 43(3): 374-380.
doi: 10.12358/j.issn.1001-5620.2026.03.010
Abstract:
Shale oil drilling is faced with challenges such as high friction, poor stability of drilling fluid additives in high-temperature high-salinity environment and increasingly stringent environment protection requirement. To address these problems, a novel ester-based lubricant LUBM-1 was developed through one-pot synthesis with raw materials such as ricinoleic acid, oleic acid, n-octanol and iso-octanol. Laboratory experiments were conducted to systematically evaluate LUBM-1 for its molecular structure characteristics and its performance in water-based drilling fluids. FT-IR characterization shows that the synthetic product has high degree of esterification and stable molecular structure. Laboratory drilling fluid experimental results show that a treatment of 1% LUBM-1 can remarkably reduce the friction coefficient of the base drilling fluid to 0.069 and the wear scar diameter, demonstrating an excellent friction reducing and wear resistant ability. The membrane formed by LUBM-1 remains stable in high-temperature and high-salinity environment; after aging at 200 ℃, it still reduces the friction of the drilling fluid by at least 80%, and in a drilling fluid containing 30% NaCl, LUBM-1 still retains high lubrication performance, showing excellent performance in high-temperature high-salinity environment. Water-based drilling fluids treated with LUBM-1 show good rheology, very low filtration rate, strong inhibitive capacity and low bio-toxicity which is required by "green-drilling". The results of the research show that LUBM-1 can significantly enhance the lubricity and borehole wall stabilizing performance of water-based drilling fluids, providing a reliable technical solution for complex shale oil drilling with high safety, high performance and environmental friendliness.
Shale oil drilling is faced with challenges such as high friction, poor stability of drilling fluid additives in high-temperature high-salinity environment and increasingly stringent environment protection requirement. To address these problems, a novel ester-based lubricant LUBM-1 was developed through one-pot synthesis with raw materials such as ricinoleic acid, oleic acid, n-octanol and iso-octanol. Laboratory experiments were conducted to systematically evaluate LUBM-1 for its molecular structure characteristics and its performance in water-based drilling fluids. FT-IR characterization shows that the synthetic product has high degree of esterification and stable molecular structure. Laboratory drilling fluid experimental results show that a treatment of 1% LUBM-1 can remarkably reduce the friction coefficient of the base drilling fluid to 0.069 and the wear scar diameter, demonstrating an excellent friction reducing and wear resistant ability. The membrane formed by LUBM-1 remains stable in high-temperature and high-salinity environment; after aging at 200 ℃, it still reduces the friction of the drilling fluid by at least 80%, and in a drilling fluid containing 30% NaCl, LUBM-1 still retains high lubrication performance, showing excellent performance in high-temperature high-salinity environment. Water-based drilling fluids treated with LUBM-1 show good rheology, very low filtration rate, strong inhibitive capacity and low bio-toxicity which is required by "green-drilling". The results of the research show that LUBM-1 can significantly enhance the lubricity and borehole wall stabilizing performance of water-based drilling fluids, providing a reliable technical solution for complex shale oil drilling with high safety, high performance and environmental friendliness.
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(6): 1-9.
doi: 10.3969/j.issn.1001-5620.2016.06.001
Abstract:
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2016, 33(6): 45-50.
doi: 10.3969/j.issn.1001-5620.2016.06.008
Abstract:
2018, 35(1): 101-104.
doi: 10.3969/j.issn.1001-5620.2018.01.019
Abstract:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
Abstract:
2016, 33(6): 10-16.
doi: 10.3969/j.issn.1001-5620.2016.06.002
Abstract:
Governed by：
China National Petroleum Corporation Ltd
China National Petroleum Corporation Ltd
Sponsored by：
CNPC Bohai Drilling Engineering Co. Ltd
CNPC Bohai Drilling Engineering Co. Ltd
Editor-in-Chief：Shi-chun Chen（Engineer Technology Research Institute,BHDC）
Deputy Editor-in-chief：
Gui-juan Wang（Engineer Technology Research Institute,BHDC）Qiang Ren（Engineer Technology Research Institute,BHDC）
Address：
Room A517, China Petroleum Tianjin Building, No. 83, Second Avenue, Tianjin Economic and Technological Development Zone
Room A517, China Petroleum Tianjin Building, No. 83, Second Avenue, Tianjin Economic and Technological Development Zone
Postcode： 300457
Tel：022-65278734022-25275527
E-mail： zjyywjy@126.com
CN 12-1486/TE
ISSN 1001-5620
