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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 A New Fracturing Fluid with Temperature Resistance of 230℃
7 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
8 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
9 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
10 A Temperature Sensitive Expanding Microcapsule Anti-Gas-Channeling Cement Slurry
2 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
3 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
6 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
8 High Performance Water Base Drilling Fluid for Shale Gas Drilling
9 High Performance Water Base Drilling Fluid for Shale Gas Drilling
10 A New Fracturing Fluid with Temperature Resistance of 230℃
Articles in press have been peer-reviewed and accepted, which are not yet assigned to volumes /issues, but are citable by Digital Object Identifier (DOI).
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2024, 41(3): 279-287.
doi: 10.12358/j.issn.1001-5620.2024.03.001
Abstract:
The marine facies Leikoupo formation in the west of Sichuan Province is a broken formation, in the later stage of horizontal drilling, it is frequently unable to exert weight on the drill bit, and borehole wall instability is another problem that haunts the drilling engineers. Analyses of these problems show that the oil-based drilling fluids presently in use have plugging capacity and lubricity that are unable to satisfy the needs of operation. To improve the plugging capacity and lubricity of the oil-based drilling fluids, based on molecular structure design, a nitrogen-containing graphene is developed through a combination of nitrogen doping modification and molten salt method. Using experimental methods, such as thermal stability measurement, dispersibility stability measurement, XRD, IR spectrum and particle size analyzer etc., the thermal stability, dispersibility, structure, functional group and particle sizes of the nitrogen-containing graphene are studied. The nitrogen-containing graphene was tested for its compatibility, plugging capacity, lubricity and high temperature resistance in active oil-based drilling fluids, and its functional mechanisms in oil-based drilling fluids are analyzed. Experimental results show that when the concentration of the nitrogen-containing graphene in an oil-based drilling fluid is 0.5%, the high temperature high pressure filter loss of the drilling fluid can be reduced by 76.2%, and the coefficient of friction reduced by about 50%. The nitrogen-containing graphene works normally at temperatures up to 180 ℃. In field operation, the use of the nitrogen-containing graphene significantly mitigated downhole problems such as the inability to exert weight on bit, high friction and borehole wall instability etc. The use of nitrogen-containing graphene has provided a new clue and technical support for solving the aforementioned drilling problems.
The marine facies Leikoupo formation in the west of Sichuan Province is a broken formation, in the later stage of horizontal drilling, it is frequently unable to exert weight on the drill bit, and borehole wall instability is another problem that haunts the drilling engineers. Analyses of these problems show that the oil-based drilling fluids presently in use have plugging capacity and lubricity that are unable to satisfy the needs of operation. To improve the plugging capacity and lubricity of the oil-based drilling fluids, based on molecular structure design, a nitrogen-containing graphene is developed through a combination of nitrogen doping modification and molten salt method. Using experimental methods, such as thermal stability measurement, dispersibility stability measurement, XRD, IR spectrum and particle size analyzer etc., the thermal stability, dispersibility, structure, functional group and particle sizes of the nitrogen-containing graphene are studied. The nitrogen-containing graphene was tested for its compatibility, plugging capacity, lubricity and high temperature resistance in active oil-based drilling fluids, and its functional mechanisms in oil-based drilling fluids are analyzed. Experimental results show that when the concentration of the nitrogen-containing graphene in an oil-based drilling fluid is 0.5%, the high temperature high pressure filter loss of the drilling fluid can be reduced by 76.2%, and the coefficient of friction reduced by about 50%. The nitrogen-containing graphene works normally at temperatures up to 180 ℃. In field operation, the use of the nitrogen-containing graphene significantly mitigated downhole problems such as the inability to exert weight on bit, high friction and borehole wall instability etc. The use of nitrogen-containing graphene has provided a new clue and technical support for solving the aforementioned drilling problems.
2024, 41(3): 288-295.
doi: 10.12358/j.issn.1001-5620.2024.03.002
Abstract:
High temperature high pressure (HTHP) environment in deep wells plays an important role in mud rheology control; omitting its effects will lead to an inaccurate knowledge of hole pressures and a negative influence on safe drilling. Based on the principle of energy conservation, a borehole temperature computation model is established. In this model a method of computing borehole temperature by coupling the effects of temperature and pressure is built up taking into account the effects of the fluid flow state on temperature and pressure. The reliability of the model is verified using data acquired from field operations. The study results show that the effect of temperature on the density and rheology of a drilling fluid is more important than the effect of pressure. As a well becomes deeper, the density and yield point of the drilling fluid in the annulus are also increasing. As the circulation time increases, the bottom hole temperature is decreasing, the density, yield point and flow index of the drilling fluid in the annulus are increasing , while the thickening index is decreasing. The ECD of the drilling fluid in the annulus under coupled temperature and pressure condition is lower than the ECD of the fluid in the same annulus without considering the coupling of temperature and pressure, the difference between the two ECD is 0.067 g/cm3. Hence, if the effects of temperature and pressure coupling on the density and rheology of a drilling fluid are not considered, a mud density lower than that is necessary to balance the formation pressure will be designed, and well kick and blowout may be induced. The results and understanding of this study provide a key theoretical base for precise evaluation of temperature and pressure in an ultra-deep well.
High temperature high pressure (HTHP) environment in deep wells plays an important role in mud rheology control; omitting its effects will lead to an inaccurate knowledge of hole pressures and a negative influence on safe drilling. Based on the principle of energy conservation, a borehole temperature computation model is established. In this model a method of computing borehole temperature by coupling the effects of temperature and pressure is built up taking into account the effects of the fluid flow state on temperature and pressure. The reliability of the model is verified using data acquired from field operations. The study results show that the effect of temperature on the density and rheology of a drilling fluid is more important than the effect of pressure. As a well becomes deeper, the density and yield point of the drilling fluid in the annulus are also increasing. As the circulation time increases, the bottom hole temperature is decreasing, the density, yield point and flow index of the drilling fluid in the annulus are increasing , while the thickening index is decreasing. The ECD of the drilling fluid in the annulus under coupled temperature and pressure condition is lower than the ECD of the fluid in the same annulus without considering the coupling of temperature and pressure, the difference between the two ECD is 0.067 g/cm3. Hence, if the effects of temperature and pressure coupling on the density and rheology of a drilling fluid are not considered, a mud density lower than that is necessary to balance the formation pressure will be designed, and well kick and blowout may be induced. The results and understanding of this study provide a key theoretical base for precise evaluation of temperature and pressure in an ultra-deep well.
2024, 41(3): 296-304.
doi: 10.12358/j.issn.1001-5620.2024.03.003
Abstract:
Slim hole drilling as an important technology is more and more used in developing deep oil and gas resources. In slim hole drilling, the much higher annular pressure losses impose a challenge to the annular pressure control. Accurate prediction of the annular pressure losses under the condition of eccentric rotation of drill string is an important theoretical and practical base for slim hole drilling. Conventional prediction models for this purpose have limited applicability and often omit the influences caused by the tool joints, thus cannot satisfy the requirements for accuracy in field operation. To solve this problem, a method of constructing empirical models with pressure loss correction factors is established based on the analyses of the effects of the tool joints on the flow-field and pressure losses in annular spaces using numerical simulation. The analyses show that the extra pressure losses produced by the tool joints are affected by the type of drilling fluid, rotary speed of drill pipe, eccentricity of drill pipe and annular flow velocity. Thus, when determining the pressure loss correction factor, the coupling of these effects should be taken into account. Using the result of numerical simulation of 152 sets of data, a model for predicting the annular pressure losses of the slim holes drilled in the Mahu oilfield in Xinjiang is established. The calculation using this model shows that there is a critical rotary speed at low drill pipe eccentricity, at which the annular pressure loss reaches maximum. At high drill pipe eccentricity, the annular pressure losses increase with rotary speed. The effects of the drill pipe eccentricity on the annular pressure losses will become complex because of the rotary speed. Using the annular pressure loss prediction model developed, the equivalent circulation density of the well MHHW-X in the Mahu oilfield was calculated and compared with the PWD data, the average error was only 1.18%, indicating that the model has high accuracy. The results of the study show that, the model established through numerical simulation for calculating annular pressure losses in slim holes, which takes into account the effects of tool joints, is able to satisfy the requirement of accuracy for field prediction of annular pressure losses, and to provide guidance to the annular pressure control in field operation.
Slim hole drilling as an important technology is more and more used in developing deep oil and gas resources. In slim hole drilling, the much higher annular pressure losses impose a challenge to the annular pressure control. Accurate prediction of the annular pressure losses under the condition of eccentric rotation of drill string is an important theoretical and practical base for slim hole drilling. Conventional prediction models for this purpose have limited applicability and often omit the influences caused by the tool joints, thus cannot satisfy the requirements for accuracy in field operation. To solve this problem, a method of constructing empirical models with pressure loss correction factors is established based on the analyses of the effects of the tool joints on the flow-field and pressure losses in annular spaces using numerical simulation. The analyses show that the extra pressure losses produced by the tool joints are affected by the type of drilling fluid, rotary speed of drill pipe, eccentricity of drill pipe and annular flow velocity. Thus, when determining the pressure loss correction factor, the coupling of these effects should be taken into account. Using the result of numerical simulation of 152 sets of data, a model for predicting the annular pressure losses of the slim holes drilled in the Mahu oilfield in Xinjiang is established. The calculation using this model shows that there is a critical rotary speed at low drill pipe eccentricity, at which the annular pressure loss reaches maximum. At high drill pipe eccentricity, the annular pressure losses increase with rotary speed. The effects of the drill pipe eccentricity on the annular pressure losses will become complex because of the rotary speed. Using the annular pressure loss prediction model developed, the equivalent circulation density of the well MHHW-X in the Mahu oilfield was calculated and compared with the PWD data, the average error was only 1.18%, indicating that the model has high accuracy. The results of the study show that, the model established through numerical simulation for calculating annular pressure losses in slim holes, which takes into account the effects of tool joints, is able to satisfy the requirement of accuracy for field prediction of annular pressure losses, and to provide guidance to the annular pressure control in field operation.
2024, 41(3): 305-317.
doi: 10.12358/j.issn.1001-5620.2024.03.004
Abstract:
In shale gas drilling in the Fuxing area, downhole troubles, such as mud losses in the Lianggaoshan formation, coexistence of well kick and mud losses in the Dongyuemiao member of the Ziliujing formation as well as borehole wall collapse which resulted in frequent pump and top drive halt, have frequently been encountered. To solve these problems, rock samples of the Lianggaoshan formation taken from the well Xingye-L2HF and the well Xingye-1002HF as well as rock samples from the Dongyuemiao member of the Ziliujing formation are analyzed with XRD diffraction for their mineral composition. Using SEM, the micromorphology of these rock samples is analyzed. By studying the field operational data, the mechanisms of borehole wall collapse and mud losses are summarized. The oil-based drilling fluid previously used is improved based on the studies for its emulsion stability, friction reduction and plugging capacity. The new oil-based drilling fluid for the drilling operation in the Fuxing area has plugging PPA of less than 2 mL and invasion depth into the sand tube of less than 2 cm. Based on the sand blocking effect in fracturing job, a mud loss control slurry formulated with compound lost circulation material, inducing agent and suspending agent was developed. The pressure bearing capacity of the mud cakes formed by this mud loss control slurry is 7 MPa, making it suitable for controlling mud losses into formations with multiple fractures. Compared with the high density diesel oil-based drilling fluid used in drilling a well in the Fuxing area previously, this new oil-based drilling fluid has lower viscosity, lower gel strengths and higher lubricity, and the occurrence of the complex situations, such as mud losses and borehole wall instability, has significantly been reduced.
In shale gas drilling in the Fuxing area, downhole troubles, such as mud losses in the Lianggaoshan formation, coexistence of well kick and mud losses in the Dongyuemiao member of the Ziliujing formation as well as borehole wall collapse which resulted in frequent pump and top drive halt, have frequently been encountered. To solve these problems, rock samples of the Lianggaoshan formation taken from the well Xingye-L2HF and the well Xingye-1002HF as well as rock samples from the Dongyuemiao member of the Ziliujing formation are analyzed with XRD diffraction for their mineral composition. Using SEM, the micromorphology of these rock samples is analyzed. By studying the field operational data, the mechanisms of borehole wall collapse and mud losses are summarized. The oil-based drilling fluid previously used is improved based on the studies for its emulsion stability, friction reduction and plugging capacity. The new oil-based drilling fluid for the drilling operation in the Fuxing area has plugging PPA of less than 2 mL and invasion depth into the sand tube of less than 2 cm. Based on the sand blocking effect in fracturing job, a mud loss control slurry formulated with compound lost circulation material, inducing agent and suspending agent was developed. The pressure bearing capacity of the mud cakes formed by this mud loss control slurry is 7 MPa, making it suitable for controlling mud losses into formations with multiple fractures. Compared with the high density diesel oil-based drilling fluid used in drilling a well in the Fuxing area previously, this new oil-based drilling fluid has lower viscosity, lower gel strengths and higher lubricity, and the occurrence of the complex situations, such as mud losses and borehole wall instability, has significantly been reduced.
2024, 41(3): 318-324.
doi: 10.12358/j.issn.1001-5620.2024.03.005
Abstract:
An ultra-high temperature coordinate bonding oligomer thinner AA-AMPS-TA (named PAAT) is synthesized as a way of dealing with the problems encountered in using high density water-based drilling fluids at elevated temperatures. These problems involve high filtration rate, high ECD and internal friction, poor mobility or even complete loss of the mobility of the drilling fluids. The thinner PAAT is synthesized through radical polymerization by introducing the molecules of tanning acids (TA) which are rich in catechol groups into the poly organic acid thinner AA-AMPS. The optimal synthesis condition of the thinner PAAT is determined through orthogonal experiment, and the thinning performance of the thinner is evaluated. The evaluation results show that after introducing TA into the molecules of the AA-AMPS, the IR spectrum of the product PAAT shows an intra-molecule hydrogen bond absorption peak, and the thermal stability of the PAAT molecules is greatly improved because of the introduction of large number of phenol groups; the decomposition temperature of the PAAT molecules is close to 500 ℃. PAAT has the ability to reduce the viscosity of low-concentration bentonite slurry and high clay concentration slurry such as one formulated with 7% bentonite and 8% kaolinite. Using PAAT, the viscosity of a high density water-based drilling fluid can be reduced by 26.5%, and after hot-rolling the water-based drilling fluid at 240 ℃, its viscosity can be reduced by 44.4%. The PAAT thinner reduces viscosity by molecule adsorption, as is verified by Zeta-potential measurement and particle size analysis. This thinner has been used in drilling the well Pengshen-101, and the viscosity and gel strengths of the drilling fluid were both satisfactorily under control at elevated temperatures.
An ultra-high temperature coordinate bonding oligomer thinner AA-AMPS-TA (named PAAT) is synthesized as a way of dealing with the problems encountered in using high density water-based drilling fluids at elevated temperatures. These problems involve high filtration rate, high ECD and internal friction, poor mobility or even complete loss of the mobility of the drilling fluids. The thinner PAAT is synthesized through radical polymerization by introducing the molecules of tanning acids (TA) which are rich in catechol groups into the poly organic acid thinner AA-AMPS. The optimal synthesis condition of the thinner PAAT is determined through orthogonal experiment, and the thinning performance of the thinner is evaluated. The evaluation results show that after introducing TA into the molecules of the AA-AMPS, the IR spectrum of the product PAAT shows an intra-molecule hydrogen bond absorption peak, and the thermal stability of the PAAT molecules is greatly improved because of the introduction of large number of phenol groups; the decomposition temperature of the PAAT molecules is close to 500 ℃. PAAT has the ability to reduce the viscosity of low-concentration bentonite slurry and high clay concentration slurry such as one formulated with 7% bentonite and 8% kaolinite. Using PAAT, the viscosity of a high density water-based drilling fluid can be reduced by 26.5%, and after hot-rolling the water-based drilling fluid at 240 ℃, its viscosity can be reduced by 44.4%. The PAAT thinner reduces viscosity by molecule adsorption, as is verified by Zeta-potential measurement and particle size analysis. This thinner has been used in drilling the well Pengshen-101, and the viscosity and gel strengths of the drilling fluid were both satisfactorily under control at elevated temperatures.
2024, 41(3): 325-329.
doi: 10.12358/j.issn.1001-5620.2024.03.006
Abstract:
The evaluation of reservoir damage is important to reservoir protection and oil and gas yield improvement. Reservoirs in the Bozhong sag of the Bohai Bay Basin are naturally fractured tight reservoirs, coring in these reservoirs is difficult and many different methods of evaluating the reservoir damage are in use, resulting in difficulties in implementing effective reservoir protection measures. To deal with this problem, combined with the actual situation of reservoirs , design and manufacture 3D printed fractured cores with transparent and visible interior and reservoir damage evaluation devices. In evaluating reservoir damage by different drill-in fluids used in Bozhong, the flow-rate damage rate instead of the permeability damage rate is used. Experimental results show that the drill-in fluid EZFLOW, which is presently in field application, has stable rheology and good filtration property. Compared with 3% bentonite drilling fluid, the EZFLOW drill-in fluid imposes smaller damage to the reservoirs, the rates of reservoir damage imposed by the EZFLOW drill-in fluid are between 11.7% and 26.2%, which are weak reservoir damage. The rate of damage to the cores is decreasing with increase in the opening degrees of the cores; for different fractured cores, the longer the cores and the wider the fractures, the higher the damage rate.
The evaluation of reservoir damage is important to reservoir protection and oil and gas yield improvement. Reservoirs in the Bozhong sag of the Bohai Bay Basin are naturally fractured tight reservoirs, coring in these reservoirs is difficult and many different methods of evaluating the reservoir damage are in use, resulting in difficulties in implementing effective reservoir protection measures. To deal with this problem, combined with the actual situation of reservoirs , design and manufacture 3D printed fractured cores with transparent and visible interior and reservoir damage evaluation devices. In evaluating reservoir damage by different drill-in fluids used in Bozhong, the flow-rate damage rate instead of the permeability damage rate is used. Experimental results show that the drill-in fluid EZFLOW, which is presently in field application, has stable rheology and good filtration property. Compared with 3% bentonite drilling fluid, the EZFLOW drill-in fluid imposes smaller damage to the reservoirs, the rates of reservoir damage imposed by the EZFLOW drill-in fluid are between 11.7% and 26.2%, which are weak reservoir damage. The rate of damage to the cores is decreasing with increase in the opening degrees of the cores; for different fractured cores, the longer the cores and the wider the fractures, the higher the damage rate.
2024, 41(3): 330-336.
doi: 10.12358/j.issn.1001-5620.2024.03.007
Abstract:
As the depth of drilling increases, the prevention and control of reservoir damage caused by drilling fluids has become increasingly prominent, and reservoir protection has become a key factor in the full release of gas field production capacity. As the well depth deepens, the various properties of the deepwater drilling fluid change, causing the degree of reservoir damage to intensify and the direction of reservoir protection performance optimization becomes unclear. Therefore, this paper combines Pearson correlation analysis and grey relational analysis to perform attribution analysis of controllable factors of drilling fluids in reservoir damage, identify the main controlling factors, and establish a gas well productivity model. The results show that the solid particle size, surface tension, mineralization degree, and high-temperature and high-pressure fluid loss of drilling fluids are the main controlling factors causing reservoir damage. According to the attribution analysis results, an optimization method using a composite of different particle size distributions of calcium carbonate as a weighting agent is proposed, which increases the permeability recovery of drilling fluids by 12.1 to 19.68%. The applicability of the model is verified by collecting field parameters from wells Y8 and Y9, and the results show that the accuracy of the model established in this paper is over 94%.
As the depth of drilling increases, the prevention and control of reservoir damage caused by drilling fluids has become increasingly prominent, and reservoir protection has become a key factor in the full release of gas field production capacity. As the well depth deepens, the various properties of the deepwater drilling fluid change, causing the degree of reservoir damage to intensify and the direction of reservoir protection performance optimization becomes unclear. Therefore, this paper combines Pearson correlation analysis and grey relational analysis to perform attribution analysis of controllable factors of drilling fluids in reservoir damage, identify the main controlling factors, and establish a gas well productivity model. The results show that the solid particle size, surface tension, mineralization degree, and high-temperature and high-pressure fluid loss of drilling fluids are the main controlling factors causing reservoir damage. According to the attribution analysis results, an optimization method using a composite of different particle size distributions of calcium carbonate as a weighting agent is proposed, which increases the permeability recovery of drilling fluids by 12.1 to 19.68%. The applicability of the model is verified by collecting field parameters from wells Y8 and Y9, and the results show that the accuracy of the model established in this paper is over 94%.
2024, 41(3): 337-343.
doi: 10.12358/j.issn.1001-5620.2024.03.008
Abstract:
Low permeability reservoir has the characteristics of dense rock, poor physical properties and small pore throat. External fluid can enter the pore throats of the reservoir under the action of capillary force, causing water lock damage, which seriously affects the production of low permeability reservoir. To solve this problem, a new type of fluorocarbon waterproof lock agent (FS-1) was prepared with perfluorooctanoic acid, ethanolamine and sodium chloroacetate as raw materials, and its structure was characterized by infrared spectrum, and the effect of fluorocarbon waterproof lock agent on the water-locking performance of brine solution in core pores was studied. The results showed that the waterproof lock agent can significantly reduce the surface tension of the brine solution (＜15 mN/m), and increase the contact angle of the distilled water on the sandstone surface to 85.3°, indicating that the developed waterproof lock agent can change the core surface wettability from hydrophilic to neutral wet, and effectively reduce the water locking damage to the cores. In addition, the waterproof lock agent (FS-1) contains multiple adsorption and salt-resistant groups, which can improve the adsorption ability of the molecule on the rock surface and makes its salt tolerance reach 7% (NaCl). Imbibition experiment, permeability test experiment and nuclear magnetic resonance experiment found that the waterproof lock agent (FS-1) slowed down the self-imbibition of the core, reduced the binding ability of the core pores to salt water and the water locking damage of the core, and improved the recovery rate of the core permeability.
Low permeability reservoir has the characteristics of dense rock, poor physical properties and small pore throat. External fluid can enter the pore throats of the reservoir under the action of capillary force, causing water lock damage, which seriously affects the production of low permeability reservoir. To solve this problem, a new type of fluorocarbon waterproof lock agent (FS-1) was prepared with perfluorooctanoic acid, ethanolamine and sodium chloroacetate as raw materials, and its structure was characterized by infrared spectrum, and the effect of fluorocarbon waterproof lock agent on the water-locking performance of brine solution in core pores was studied. The results showed that the waterproof lock agent can significantly reduce the surface tension of the brine solution (＜15 mN/m), and increase the contact angle of the distilled water on the sandstone surface to 85.3°, indicating that the developed waterproof lock agent can change the core surface wettability from hydrophilic to neutral wet, and effectively reduce the water locking damage to the cores. In addition, the waterproof lock agent (FS-1) contains multiple adsorption and salt-resistant groups, which can improve the adsorption ability of the molecule on the rock surface and makes its salt tolerance reach 7% (NaCl). Imbibition experiment, permeability test experiment and nuclear magnetic resonance experiment found that the waterproof lock agent (FS-1) slowed down the self-imbibition of the core, reduced the binding ability of the core pores to salt water and the water locking damage of the core, and improved the recovery rate of the core permeability.
2024, 41(3): 344-349.
doi: 10.12358/j.issn.1001-5620.2024.03.009
Abstract:
In high temperature extended reach well drilling, the water-based drilling fluids are generally treated with liquid lubricants to alleviate friction. In high density, high salinity and high temperature conditions, the lubricity of the liquid lubricants is not enough to reduce the friction to the required level, causing from time to time downhole troubles such as halting of drilling string, stuck pipe and wear and tear of drill tools. To solve these problems, a sulfurized fatty acid ester is synthesized in laboratory and is compounded with lubricants to obtain a compound lubricant QT311. Adding the lubricant QT311 into the HTFlow high temperature high pressure water-based drilling fluid greatly improves the lubricity of the drilling fluid. Testing the QT311 treated HTFlow drilling fluid on four-ball friction tester shows that treatment of 1%QT311 reduces the coefficient of friction by 64% and the diameter of the wear scars is reduced by 43%. These results indicate the QT311 as a lubricant is superior to several widely used commercial lubricants. Analysis of the surface of the friction pair with SEM shows that QT311 react chemically with iron during friction to form sulfur-iron extreme pressure membrane, thereby improving the friction-reducing performance of the drilling fluid. The laboratory experiments also show that QT311 has excellent compatibility with the HTFlow drilling fluid, anti-hydrolysis performance, salt resistance and high temperature resistance. The experimental results have provided a reference for further studies on drill-in fluid lubricants.
In high temperature extended reach well drilling, the water-based drilling fluids are generally treated with liquid lubricants to alleviate friction. In high density, high salinity and high temperature conditions, the lubricity of the liquid lubricants is not enough to reduce the friction to the required level, causing from time to time downhole troubles such as halting of drilling string, stuck pipe and wear and tear of drill tools. To solve these problems, a sulfurized fatty acid ester is synthesized in laboratory and is compounded with lubricants to obtain a compound lubricant QT311. Adding the lubricant QT311 into the HTFlow high temperature high pressure water-based drilling fluid greatly improves the lubricity of the drilling fluid. Testing the QT311 treated HTFlow drilling fluid on four-ball friction tester shows that treatment of 1%QT311 reduces the coefficient of friction by 64% and the diameter of the wear scars is reduced by 43%. These results indicate the QT311 as a lubricant is superior to several widely used commercial lubricants. Analysis of the surface of the friction pair with SEM shows that QT311 react chemically with iron during friction to form sulfur-iron extreme pressure membrane, thereby improving the friction-reducing performance of the drilling fluid. The laboratory experiments also show that QT311 has excellent compatibility with the HTFlow drilling fluid, anti-hydrolysis performance, salt resistance and high temperature resistance. The experimental results have provided a reference for further studies on drill-in fluid lubricants.
2024, 41(3): 350-356.
doi: 10.12358/j.issn.1001-5620.2024.03.010
Abstract:
The Feixianguan gas reservoir in northeast Sichuan is a high to ultra-high sulfur content reservoir. Based on the analyses of the geology of the Feixianguan formation and the difficulties in drilling fluid operation, a desulfurization measure is presented for field operation with oil based drilling fluids. High performance desulphurizing agents are first selected through laboratory experiment, and studies on the compounding of these agents are conducted to develop a compound desulphurizing agent. Evaluation of the performance of the compound desulphurizing agent to remove sulfur at elevated temperatures shows that the compound desulphurizing agent containing 3%YT-3+3%CLC-2 and 3%JD-2 has percent H2S prevention of 99.14% and percent H2S removal of 100%. The zinc-based desulfurizing agent in the formula reacted with H2S in the drilling fluids to produce insoluble chemical ZnS. The triazine and alcohol ether amide desulfurizing agents mainly remove H2S through fast and irreversible physical and chemical reactions. This desulfurization technology has been successfully applied on the well Po-005-X4 and the well Po-002-H5 when drilled into the high sulfur content Feixianguan formation, no H2S has been detected during drilling and during circulation after tripping for degassing, and the S2− content of the drilling fluid is zero throughout the whole drilling operation. The successful field operation fully demonstrates that the technology has a significant desulfurization performance and can meet the requirements of drilling high sulfur wells.
The Feixianguan gas reservoir in northeast Sichuan is a high to ultra-high sulfur content reservoir. Based on the analyses of the geology of the Feixianguan formation and the difficulties in drilling fluid operation, a desulfurization measure is presented for field operation with oil based drilling fluids. High performance desulphurizing agents are first selected through laboratory experiment, and studies on the compounding of these agents are conducted to develop a compound desulphurizing agent. Evaluation of the performance of the compound desulphurizing agent to remove sulfur at elevated temperatures shows that the compound desulphurizing agent containing 3%YT-3+3%CLC-2 and 3%JD-2 has percent H2S prevention of 99.14% and percent H2S removal of 100%. The zinc-based desulfurizing agent in the formula reacted with H2S in the drilling fluids to produce insoluble chemical ZnS. The triazine and alcohol ether amide desulfurizing agents mainly remove H2S through fast and irreversible physical and chemical reactions. This desulfurization technology has been successfully applied on the well Po-005-X4 and the well Po-002-H5 when drilled into the high sulfur content Feixianguan formation, no H2S has been detected during drilling and during circulation after tripping for degassing, and the S2− content of the drilling fluid is zero throughout the whole drilling operation. The successful field operation fully demonstrates that the technology has a significant desulfurization performance and can meet the requirements of drilling high sulfur wells.
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
摘要：
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
以妥尔油脂肪酸和马来酸酐为主要原料合成了一种油基钻井液抗高温主乳化剂HT-MUL,并确定了妥尔油脂肪酸单体的最佳酸值及马来酸酐单体的最优加量。对HT-MUL进行了单剂评价,结果表明HT-MUL的乳化能力良好,配制的油水比为60:40的油包水乳液的破乳电压最高可达490 V,90:10的乳液破乳电压最高可达1000 V。从抗温性、滤失性、乳化率方面对HT-MUL和国内外同类产品进行了对比,结果表明HT-MUL配制的乳液破乳电压更大、滤失量更小、乳化率更高,整体性能优于国内外同类产品。应用主乳化剂HT-MUL配制了高密度的油基钻井液,其性能评价表明体系的基本性能良好,在220℃高温热滚后、破乳电压高达800 V,滤失量低于5 mL。HT-MUL配制的油基钻井液具有良好的抗高温性和乳化稳定性。
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。
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。
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。
2016, 33(1): 17-21.
doi: 10.3969/j.issn.1001-5620.2016.01.004
摘要：
目前中国页岩气水平井定向段及水平段钻井均使用油基钻井液,但油基岩屑处理费用昂贵,急需开发和应用一种具有环境保护特性的高性能水基钻井液体系。介绍了2种高性能水基钻井液体系的室内实验和现场试验效果。在长宁H9-4井水平段、长宁H9-3和长宁H9-5井定向至完井段试验了GOF高性能水基钻井液体系,该体系采用的是聚合物封堵抑制方案,完全采用水基润滑方式;在昭通区块YS108H4-2井水平段试验了高润强抑制性水基钻井液体系,该体系采用的是有机、无机盐复合防膨方案以及润滑剂与柴油复合润滑方式。现场应用表明,定向段机械钻速提高50%~75%,水平段机械钻速提高75%~100%。通过实验数据及现场使用情况,对比分析了2种体系的优劣,找出了他们各自存在的问题,并提出了改进的思路,为高性能水基钻井液的进一步完善提供一些经验。
目前中国页岩气水平井定向段及水平段钻井均使用油基钻井液,但油基岩屑处理费用昂贵,急需开发和应用一种具有环境保护特性的高性能水基钻井液体系。介绍了2种高性能水基钻井液体系的室内实验和现场试验效果。在长宁H9-4井水平段、长宁H9-3和长宁H9-5井定向至完井段试验了GOF高性能水基钻井液体系,该体系采用的是聚合物封堵抑制方案,完全采用水基润滑方式;在昭通区块YS108H4-2井水平段试验了高润强抑制性水基钻井液体系,该体系采用的是有机、无机盐复合防膨方案以及润滑剂与柴油复合润滑方式。现场应用表明,定向段机械钻速提高50%~75%,水平段机械钻速提高75%~100%。通过实验数据及现场使用情况,对比分析了2种体系的优劣,找出了他们各自存在的问题,并提出了改进的思路,为高性能水基钻井液的进一步完善提供一些经验。
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(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。
2017, 34(1): 54-59.
doi: 10.3969/j.issn.1001-5620.2017.01.010
摘要：
库车山前深部巨厚盐膏层地质特征复杂，层间超高压盐水普遍发育，纵横向规律性差，地层压力变化大，预测难度高。盐膏层钻井过程中超高压盐水侵入井筒后，钻井液性能恶化，导致喷、漏、卡等复杂事故频发，严重影响安全快速钻井。结合超高压盐水层钻井特征，通过分析超高压盐水赋存的圈闭特点及实钻情况，在钻井液的盐水污染容量限实验模拟和评价的基础上，开展了超高压盐水层控压排水技术的探索与实践，形成了控压排水配套新技术，通过控制节流阀调节井口回压和钻井液排量等手段，让地层盐水按一定比例均匀侵入到环空钻井液中，单次放水量不超过环空钻井液量的10%，多次放出盐水，降低高压盐水层的地层压力系数。解决了库车山前超深超高压盐水层安全钻井难题。现场试验表明，采取合理的控压排水方法能够降低盐水层的压力，在溢流与井漏的矛盾中找到压力平衡点，有利于井控安全的井筒状态。
库车山前深部巨厚盐膏层地质特征复杂，层间超高压盐水普遍发育，纵横向规律性差，地层压力变化大，预测难度高。盐膏层钻井过程中超高压盐水侵入井筒后，钻井液性能恶化，导致喷、漏、卡等复杂事故频发，严重影响安全快速钻井。结合超高压盐水层钻井特征，通过分析超高压盐水赋存的圈闭特点及实钻情况，在钻井液的盐水污染容量限实验模拟和评价的基础上，开展了超高压盐水层控压排水技术的探索与实践，形成了控压排水配套新技术，通过控制节流阀调节井口回压和钻井液排量等手段，让地层盐水按一定比例均匀侵入到环空钻井液中，单次放水量不超过环空钻井液量的10%，多次放出盐水，降低高压盐水层的地层压力系数。解决了库车山前超深超高压盐水层安全钻井难题。现场试验表明，采取合理的控压排水方法能够降低盐水层的压力，在溢流与井漏的矛盾中找到压力平衡点，有利于井控安全的井筒状态。
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:
2018, 35(1): 101-104.
doi: 10.3969/j.issn.1001-5620.2018.01.019
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
Abstract:
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2018, 35(1): 71-76.
doi: 10.3969/j.issn.1001-5620.2018.01.014
Abstract:
Competent Authorities：China National Petroleum Corporation Ltd
Sponsored by：CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
Editor-in-Chief：Shi-chun Chen
Address： Editorial Department of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province
Postcode： 062552
Tel：（0317）2725487 2722354
E-mail： zjyywjy@126.com
CN13-1118/TE
ISSN1001-5620
