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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 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
8 Progress in Studying Cement Sheath Failure in Perforated Wells
9 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
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
7 High Performance Water Base Drilling Fluid for Shale Gas Drilling
8 High Performance Water Base Drilling Fluid for Shale Gas Drilling
9 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
10 Study on Hydrophobic Nano Calcium Carbonate Drilling Fluid
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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2023, 40(4): 415-422.
doi: 10.12358/j.issn.1001-5620.2023.04.001
Abstract:
The methods of preventing and curing gas hydrate in deepwater drilling are too preservative. In the west of the South China Sea, the gas hydrate inhibitive drilling fluid HEM used in the deepwater drilling is quite expensive and the penetration rate is low. To reduce the mud cost and shorten the drilling time, several issues were studied, including the phase equilibrium curves of hydrate generation with different gas components, the regions for gas hydrate generation under different operating conditions, and the methods of dealing with borehole blockage by the gas hydrates. All these studies were conducted with the low cost polymer drilling fluids used in the deepwater drilling in the BD block in the Yinggehai basin (South China Sea). Potential regions for the generation of gas hydrates under different operating conditions were obtained. Based on these studies, poly (M-vinyl caprolactam) was selected as the kinetic gas hydrate inhibitor to inhibit the generation of gas hydrates glycol selected as the thermodynamic inhibitor to remove blockage in a wellbore by gas hydrates. Ten new kinetic inhibitors were designed in laboratory study, of which the DS-A3 inhibitor has good inhibitive capacity for gas hydrate generation. Laboratory study and field (block BD) application showed that: 1) in operating conditions such as normal drilling, circulation and well shut-in, no gas hydrate generation region exists, as such, there is no risks of wellbore blockage. 2) Considering the inhibitive effect and cost together, 0.8% poly (M-vinyl caprolactam) has the best inhibitive effect for gas hydrate generation, and 45% glycol has the best effect for removing blockage of a wellbore by gas hydrate. 3) When there are no complex downhole operating conditions, if the rig down time does not exceed 15 hours, polymer drilling fluids can be directly used in deepwater drilling. In this way the drilling fluid cost for a single well can be reduced by 50%-70%, a good economic benefit.
The methods of preventing and curing gas hydrate in deepwater drilling are too preservative. In the west of the South China Sea, the gas hydrate inhibitive drilling fluid HEM used in the deepwater drilling is quite expensive and the penetration rate is low. To reduce the mud cost and shorten the drilling time, several issues were studied, including the phase equilibrium curves of hydrate generation with different gas components, the regions for gas hydrate generation under different operating conditions, and the methods of dealing with borehole blockage by the gas hydrates. All these studies were conducted with the low cost polymer drilling fluids used in the deepwater drilling in the BD block in the Yinggehai basin (South China Sea). Potential regions for the generation of gas hydrates under different operating conditions were obtained. Based on these studies, poly (M-vinyl caprolactam) was selected as the kinetic gas hydrate inhibitor to inhibit the generation of gas hydrates glycol selected as the thermodynamic inhibitor to remove blockage in a wellbore by gas hydrates. Ten new kinetic inhibitors were designed in laboratory study, of which the DS-A3 inhibitor has good inhibitive capacity for gas hydrate generation. Laboratory study and field (block BD) application showed that: 1) in operating conditions such as normal drilling, circulation and well shut-in, no gas hydrate generation region exists, as such, there is no risks of wellbore blockage. 2) Considering the inhibitive effect and cost together, 0.8% poly (M-vinyl caprolactam) has the best inhibitive effect for gas hydrate generation, and 45% glycol has the best effect for removing blockage of a wellbore by gas hydrate. 3) When there are no complex downhole operating conditions, if the rig down time does not exceed 15 hours, polymer drilling fluids can be directly used in deepwater drilling. In this way the drilling fluid cost for a single well can be reduced by 50%-70%, a good economic benefit.
2023, 40(4): 423-430.
doi: 10.12358/j.issn.1001-5620.2023.04.002
Abstract:
Many kinds of hydrocarbon reservoir damages with complex mechanisms have been encountered in every phase of oil and gas field exploration and development. Conventional core flow test used in evaluating the sensibility damage of a reservoir can give reliable test results, however, this test is both expensive (coring, for instance) and time consuming. Researches have shown that a model established with neural network and random forest algorithm on small-scale samples can be used to save time and money in predicting the properties of samples. In this study, the data of a set of small-scale samples tested in laboratory is obtained from the block X. The training-sets and testing-sets are then selected on the samples. By extensively comparing the results of three algorithms, which are the BP neural network algorithm, the radial basis function neural network algorithm and the random forest algorithm, the random forest algorithm is finally selected as the main method of quantitatively diagnosing the sensitivity damage of hydrocarbon reservoirs. To improve the prediction accuracy, algorithms such as grid search are used in hyperparameter optimization, and data dimensionality reduction is performed based on factor weight. A complete model is finally established based on the studies conducted. The average R2 value of the four kinds of reservoir damage model is 0.852, with a prediction accuracy between 90.00% and 95.68%.
Many kinds of hydrocarbon reservoir damages with complex mechanisms have been encountered in every phase of oil and gas field exploration and development. Conventional core flow test used in evaluating the sensibility damage of a reservoir can give reliable test results, however, this test is both expensive (coring, for instance) and time consuming. Researches have shown that a model established with neural network and random forest algorithm on small-scale samples can be used to save time and money in predicting the properties of samples. In this study, the data of a set of small-scale samples tested in laboratory is obtained from the block X. The training-sets and testing-sets are then selected on the samples. By extensively comparing the results of three algorithms, which are the BP neural network algorithm, the radial basis function neural network algorithm and the random forest algorithm, the random forest algorithm is finally selected as the main method of quantitatively diagnosing the sensitivity damage of hydrocarbon reservoirs. To improve the prediction accuracy, algorithms such as grid search are used in hyperparameter optimization, and data dimensionality reduction is performed based on factor weight. A complete model is finally established based on the studies conducted. The average R2 value of the four kinds of reservoir damage model is 0.852, with a prediction accuracy between 90.00% and 95.68%.
2023, 40(4): 431-437.
doi: 10.12358/j.issn.1001-5620.2023.04.003
Abstract:
During the development of the carbonate reservoir of the Tahe oilfield, the conventional polysulfonate drilling fluid damages reservoir duo to non-acid-soluble solid phase after loss, and sulfonalized agent does not conform to the concept of green development. The oilfield water is introduced to formulate a solid free drilling fluid to avoid damage reservoir from solid, and the key treatment agents such as anti-high temperature anti-calcium viscosifier, flow pattern modifiers, high-temperature anti-calcium polymer filtrate reducer. The dual-protective oilfield water drilling fluids system without solid was developed. Indoor evaluation datas show that the drilling fluid was heat resistant to 150 ℃, the ratio between yield point and plastic viscosity is as high as 0.68～0.76 Pa/mPa·s, the EC50 value of biological toxicity indicators is as high as 28,600 mg/L, and the bio-degradation index BOD5/CODCr is as high as 21.35%. The dynamic permeability recovery value is as high as 91.8%, which has good formation damage control performance. The developed dual-protective oilfield water drilling fluids without solid were successfully used in more than ten sidetrack wells,and the application effect was significant.
During the development of the carbonate reservoir of the Tahe oilfield, the conventional polysulfonate drilling fluid damages reservoir duo to non-acid-soluble solid phase after loss, and sulfonalized agent does not conform to the concept of green development. The oilfield water is introduced to formulate a solid free drilling fluid to avoid damage reservoir from solid, and the key treatment agents such as anti-high temperature anti-calcium viscosifier, flow pattern modifiers, high-temperature anti-calcium polymer filtrate reducer. The dual-protective oilfield water drilling fluids system without solid was developed. Indoor evaluation datas show that the drilling fluid was heat resistant to 150 ℃, the ratio between yield point and plastic viscosity is as high as 0.68～0.76 Pa/mPa·s, the EC50 value of biological toxicity indicators is as high as 28,600 mg/L, and the bio-degradation index BOD5/CODCr is as high as 21.35%. The dynamic permeability recovery value is as high as 91.8%, which has good formation damage control performance. The developed dual-protective oilfield water drilling fluids without solid were successfully used in more than ten sidetrack wells,and the application effect was significant.
2023, 40(4): 438-445.
doi: 10.12358/j.issn.1001-5620.2023.04.004
Abstract:
Borehole wall instability has long been a problem encountered in drilling the Shaximiao formation in the block Zhongjiang, western Sichuan. To solve this problem, the claystones from the Shaximiao formation was studied for their mineral composition, microstructure and physical-chemical properties. The study results have revealed the mechanisms of borehole wall instability of the Shaximiao formation. The Shaximiao formation is a typical hard and brittle rock with high content of clay minerals (mostly illite) which are strongly hydratable. The formation is developed with plenty of micrometer- and nanometer-sized fractures, which will expand continually when mud filtrate invasion take place and finally, collapse. The inhomogeneous distribution of illite and illite/montmorillonite mixed layer in the rocks, high specific water absorptivity and high repulsive force of the hydration films have made the expansion of the microfractures even worse. An alkyl glycoside inhibitive agent and a nanometer plugging agent were selected to formulate a high-performance anti-collapse drilling fluid based on the “Multivariate collaboration” borehole stabilization theory. Laboratory experiment on the performance of this drilling fluid has shown that this drilling fluid has good rheology, API filter loss of less than 3 mL, HTHP filter loss of 8 mL or less, percent cuttings recovery of 98.87%, swelling rate of less than 3%. These data indicate that the drilling fluid has good inhibitive capacity and good capacity of plugging the microfractures and micropores. Field application has shown that the alkyl glycoside drilling fluid can effectively inhibit the collapse of the Shaximiao formation. High ROP was obtained with this drilling fluid, and no downhole troubles have been encountered. The use of the alkyl glycoside drilling fluid has provided a technical support to safely, efficiently and economically drill the Shaximiao formation.
Borehole wall instability has long been a problem encountered in drilling the Shaximiao formation in the block Zhongjiang, western Sichuan. To solve this problem, the claystones from the Shaximiao formation was studied for their mineral composition, microstructure and physical-chemical properties. The study results have revealed the mechanisms of borehole wall instability of the Shaximiao formation. The Shaximiao formation is a typical hard and brittle rock with high content of clay minerals (mostly illite) which are strongly hydratable. The formation is developed with plenty of micrometer- and nanometer-sized fractures, which will expand continually when mud filtrate invasion take place and finally, collapse. The inhomogeneous distribution of illite and illite/montmorillonite mixed layer in the rocks, high specific water absorptivity and high repulsive force of the hydration films have made the expansion of the microfractures even worse. An alkyl glycoside inhibitive agent and a nanometer plugging agent were selected to formulate a high-performance anti-collapse drilling fluid based on the “Multivariate collaboration” borehole stabilization theory. Laboratory experiment on the performance of this drilling fluid has shown that this drilling fluid has good rheology, API filter loss of less than 3 mL, HTHP filter loss of 8 mL or less, percent cuttings recovery of 98.87%, swelling rate of less than 3%. These data indicate that the drilling fluid has good inhibitive capacity and good capacity of plugging the microfractures and micropores. Field application has shown that the alkyl glycoside drilling fluid can effectively inhibit the collapse of the Shaximiao formation. High ROP was obtained with this drilling fluid, and no downhole troubles have been encountered. The use of the alkyl glycoside drilling fluid has provided a technical support to safely, efficiently and economically drill the Shaximiao formation.
2023, 40(4): 446-452, 461.
doi: 10.12358/j.issn.1001-5620.2023.04.005
Abstract:
The Longmaxi formation in the Changning block (Sichuan Oilfield) is drilled with oil-based drilling fluids. This formation is developed with microfractures and hence mud losses have frequently happened in the past. Mud losses have been controlled with bridging particles formulated in oil-based slurries, which has been proved unsuccessful and time consuming. To deal with this problem, a compound oil-based gel has been developed with animal fats, vegetable oils and epoxy resin. This oil-based gel can invade into the fractures in the formation rocks to seal them off, thereby increasing the success rate of mud loss control. Considering the practicability of field application, the compressive strength, thickening time and performance against contamination from oil-based muds of this gel were evaluated in laboratory test, and its ability to combat mud losses was also evaluated. The laboratory test results have shown that the gel has compressive strength of 5.1 MPa, and the gelling time can be controlled at more than 3 hours, which is enough to perform field operation safely. Oil-based drilling fluids have only a very slight effect on the gel strength of the gel and do not cause the thickening time of the gel to shorten. All properties of the oil-based gel indicate that it is suitable for use in controlling mud losses through microfractures in hole sections drilled with oil-based drilling fluids.
The Longmaxi formation in the Changning block (Sichuan Oilfield) is drilled with oil-based drilling fluids. This formation is developed with microfractures and hence mud losses have frequently happened in the past. Mud losses have been controlled with bridging particles formulated in oil-based slurries, which has been proved unsuccessful and time consuming. To deal with this problem, a compound oil-based gel has been developed with animal fats, vegetable oils and epoxy resin. This oil-based gel can invade into the fractures in the formation rocks to seal them off, thereby increasing the success rate of mud loss control. Considering the practicability of field application, the compressive strength, thickening time and performance against contamination from oil-based muds of this gel were evaluated in laboratory test, and its ability to combat mud losses was also evaluated. The laboratory test results have shown that the gel has compressive strength of 5.1 MPa, and the gelling time can be controlled at more than 3 hours, which is enough to perform field operation safely. Oil-based drilling fluids have only a very slight effect on the gel strength of the gel and do not cause the thickening time of the gel to shorten. All properties of the oil-based gel indicate that it is suitable for use in controlling mud losses through microfractures in hole sections drilled with oil-based drilling fluids.
2023, 40(4): 453-461.
doi: 10.12358/j.issn.1001-5620.2023.04.006
Abstract:
During oil and gas drilling in deep complex formations, the technical requirements of high temperature and salt-resistance of drilling fluid should be met. In this paper, a polymer brush lubricant (HLM) for water-based drilling fluids was prepared using methyl methacrylate, lauryl acrylate and 2-hydroxyethyl acrylate as the main raw materials and 2-methylpropionitrile as the initiator. The HLM was characterized by means of Fourier infrared spectroscopy, nuclear magnetic resonance spectroscopy, thermogravimetric analysis and gel chromatography. The compatibility of HLM with drilling fluids and the lubricity performance of HLM under high temperature, high salt and high density conditions were evaluated. The lubricity was further analyzed using a multifunctional material surface performance tester and a four-ball friction tester. The experimental results showed that HLM had a good thermal stability with a weight average molecular mass of 3494. HLM had good compatibility with the bentonite-based mud at room temperature and had essentially no effect on rheology. The temperature resistance can reach 260 ℃.When concentration of HLM was 2%, the lubrication coefficient reduction rates were 91.16% under room temperature, 88.24% after ageing at 260 ℃, 75.69% for the saturated salt-based mud, and larger than 40% in the high-density drilling mud. The multifunctional material surface performance experiment further demonstrated that HLM could substantially reduce metal-to-metal friction. The four-ball friction experiment demonstrated that HLM could form a stable lubricating film on metal surfaces. Since HLM had multiple adsorption sites and strong adsorption capacity, the adsorption film still had high strength under high temperature and high salt conditions, giving HLM good lubricating properties. This paper can provide technical reference for the construction of drilling fluids for deep/ultra-deep formations.
During oil and gas drilling in deep complex formations, the technical requirements of high temperature and salt-resistance of drilling fluid should be met. In this paper, a polymer brush lubricant (HLM) for water-based drilling fluids was prepared using methyl methacrylate, lauryl acrylate and 2-hydroxyethyl acrylate as the main raw materials and 2-methylpropionitrile as the initiator. The HLM was characterized by means of Fourier infrared spectroscopy, nuclear magnetic resonance spectroscopy, thermogravimetric analysis and gel chromatography. The compatibility of HLM with drilling fluids and the lubricity performance of HLM under high temperature, high salt and high density conditions were evaluated. The lubricity was further analyzed using a multifunctional material surface performance tester and a four-ball friction tester. The experimental results showed that HLM had a good thermal stability with a weight average molecular mass of 3494. HLM had good compatibility with the bentonite-based mud at room temperature and had essentially no effect on rheology. The temperature resistance can reach 260 ℃.When concentration of HLM was 2%, the lubrication coefficient reduction rates were 91.16% under room temperature, 88.24% after ageing at 260 ℃, 75.69% for the saturated salt-based mud, and larger than 40% in the high-density drilling mud. The multifunctional material surface performance experiment further demonstrated that HLM could substantially reduce metal-to-metal friction. The four-ball friction experiment demonstrated that HLM could form a stable lubricating film on metal surfaces. Since HLM had multiple adsorption sites and strong adsorption capacity, the adsorption film still had high strength under high temperature and high salt conditions, giving HLM good lubricating properties. This paper can provide technical reference for the construction of drilling fluids for deep/ultra-deep formations.
2023, 40(4): 462-466.
doi: 10.12358/j.issn.1001-5620.2023.04.007
Abstract:
Fast plugging of microfractures and micropores in the hard brittle shales and deep buried sandstone/mudstone interbeds is one of the challenges that needs to be dealt with in solving borehole wall collapse in drilling the shale formation and reservoir damage. Graphene materials, because of their excellent properties such as nanometer sizes and layered membrane structures, can be used to solve these downhole problems at low concentrations and with high efficiency. A graphene slurry with good stability is prepared in laboratory with graphite using rolling lift-off technique. Evaluation of the performance of the graphene slurry shows that the D50 of the graphene particles is ±5 μm. The graphene slurry has good filtration control property and shale swelling inhibitive capacity. PPA test results show that the graphene slurry is able to effectively seal off the micropores on the sand plate. The application of the graphene slurry on two wells shows that it has good compatibility with the water based drilling fluids used and improves the plugging efficiency of the drilling fluids. Using this graphene slurry, the borehole wall collapse problem previously encountered is successfully solved.
Fast plugging of microfractures and micropores in the hard brittle shales and deep buried sandstone/mudstone interbeds is one of the challenges that needs to be dealt with in solving borehole wall collapse in drilling the shale formation and reservoir damage. Graphene materials, because of their excellent properties such as nanometer sizes and layered membrane structures, can be used to solve these downhole problems at low concentrations and with high efficiency. A graphene slurry with good stability is prepared in laboratory with graphite using rolling lift-off technique. Evaluation of the performance of the graphene slurry shows that the D50 of the graphene particles is ±5 μm. The graphene slurry has good filtration control property and shale swelling inhibitive capacity. PPA test results show that the graphene slurry is able to effectively seal off the micropores on the sand plate. The application of the graphene slurry on two wells shows that it has good compatibility with the water based drilling fluids used and improves the plugging efficiency of the drilling fluids. Using this graphene slurry, the borehole wall collapse problem previously encountered is successfully solved.
2023, 40(4): 467-474.
doi: 10.12358/j.issn.1001-5620.2023.04.008
Abstract:
High density drilling fluids weighted with barite were used in deep well and ultra-deep well drilling in the Shunbei block. Several problems were found with these drilling fluids during drilling, such as difficulties in maintaining mud rheology, poor settling stability as well as reservoir damage by the solid particles from the drilling fluids etc. Micromax as a weight material has been reported in dealing with these problems, but the use of Micromax in China has been limited because of technical monopolization and high cost. A new drilling fluid micro-manganese weighting additive DFMT01 was developed using the “manganese ore method”. As a cost-effective domestic micro-manganese product, DFMT01 was used to formulate reservoir protective drilling fluids. The molecular structure of DFMT01 was characterized, and the performance of DFMT01 was evaluated in the high density sulfonated drilling fluids used in the Shunbei block. The results of field application of DFMT01 show that it has good physical and chemical properties. DFMT01 has a density of 4.7 g/cm3, an acid solubility of at least 99%, a D50 of 1.17 μm and particle sphericity of 0.967, all these properties are comparable to the equivalent products from abroad. Drilling fluids weighted with DFMT01 have rheology, filtration property, erosion property and reservoir protective capacity equal to or better than those of the drilling fluids weighted with Micromax. A “neutralize to precipitate calcium carbonate – recover manganese ions with sulfuric acid – coagulate to treat the waste water” method was used in the treatment of high concentration acidic waste liquids containing manganese. Using this method, waste waters after treatment has mass concentration of manganese of 0.45 mg/L and SS of 10 mg/L, reaching the requirement of the first-level standard. The waste water treatment method can be used in the manufacturing, using and treatment of DFMT01 as a closed loop. DFMT01 is a weighting material having excellent property, low cost and very broad promotion and application prospects.
High density drilling fluids weighted with barite were used in deep well and ultra-deep well drilling in the Shunbei block. Several problems were found with these drilling fluids during drilling, such as difficulties in maintaining mud rheology, poor settling stability as well as reservoir damage by the solid particles from the drilling fluids etc. Micromax as a weight material has been reported in dealing with these problems, but the use of Micromax in China has been limited because of technical monopolization and high cost. A new drilling fluid micro-manganese weighting additive DFMT01 was developed using the “manganese ore method”. As a cost-effective domestic micro-manganese product, DFMT01 was used to formulate reservoir protective drilling fluids. The molecular structure of DFMT01 was characterized, and the performance of DFMT01 was evaluated in the high density sulfonated drilling fluids used in the Shunbei block. The results of field application of DFMT01 show that it has good physical and chemical properties. DFMT01 has a density of 4.7 g/cm3, an acid solubility of at least 99%, a D50 of 1.17 μm and particle sphericity of 0.967, all these properties are comparable to the equivalent products from abroad. Drilling fluids weighted with DFMT01 have rheology, filtration property, erosion property and reservoir protective capacity equal to or better than those of the drilling fluids weighted with Micromax. A “neutralize to precipitate calcium carbonate – recover manganese ions with sulfuric acid – coagulate to treat the waste water” method was used in the treatment of high concentration acidic waste liquids containing manganese. Using this method, waste waters after treatment has mass concentration of manganese of 0.45 mg/L and SS of 10 mg/L, reaching the requirement of the first-level standard. The waste water treatment method can be used in the manufacturing, using and treatment of DFMT01 as a closed loop. DFMT01 is a weighting material having excellent property, low cost and very broad promotion and application prospects.
2023, 40(4): 475-480.
doi: 10.12358/j.issn.1001-5620.2023.04.009
Abstract:
In order to improve the bubble inhibition and environmental protection performance of the waterproof locking agent for drilling fluid, a natural modified product SMFS-1 was synthesized from alginic acid, 2-(2-aminoethylamino)ethanol (AEEA), epichlorohydrin (ECH) and pentaerythritol (PETP) as raw materials. The molecular structure was characterized by Fourier infrared spectrometer (FT-IR). The test results of waterproof lock performance show that the surface tension of aqueous solution can be reduced to less than 25 mN/m after the addition of SMFS-1, which can reduce the volume of core self-absorption, promote the change of rock surface from hydrophilic to neutral, and increase the recovery value of core permeability to more than 80%. SMFS-1 is resistant to temperature up to 120 ℃, has excellent adsorption performance, no bubbling effect, and has little impact on rheological properties and filtration properties of drilling fluid. The environmental performance test results showed that the semi-lethal concentration (EC50) of SMFS-1 was 32,250 mg/L, and the biodegradability evaluation index (Y) was 17.36, which met the emission standard and was easy to biodegrade.
In order to improve the bubble inhibition and environmental protection performance of the waterproof locking agent for drilling fluid, a natural modified product SMFS-1 was synthesized from alginic acid, 2-(2-aminoethylamino)ethanol (AEEA), epichlorohydrin (ECH) and pentaerythritol (PETP) as raw materials. The molecular structure was characterized by Fourier infrared spectrometer (FT-IR). The test results of waterproof lock performance show that the surface tension of aqueous solution can be reduced to less than 25 mN/m after the addition of SMFS-1, which can reduce the volume of core self-absorption, promote the change of rock surface from hydrophilic to neutral, and increase the recovery value of core permeability to more than 80%. SMFS-1 is resistant to temperature up to 120 ℃, has excellent adsorption performance, no bubbling effect, and has little impact on rheological properties and filtration properties of drilling fluid. The environmental performance test results showed that the semi-lethal concentration (EC50) of SMFS-1 was 32,250 mg/L, and the biodegradability evaluation index (Y) was 17.36, which met the emission standard and was easy to biodegrade.
2023, 40(4): 481-486.
doi: 10.12358/j.issn.1001-5620.2023.04.010
Abstract:
A water based mud was formulated with lignite resin and bentonite in laboratory in accordance with the standard SY/T 5679—2017. After agitating the mud with high-speed mixer, the mud was treated with ultrasonic wave to investigate the effects of ultrasonic vibration on the colloidal properties of the mud. The purpose of this test is to find a new way of preparing mud with which the performance of the existing mud additives can be improved. The test results show that ultrasonic vibration can remarkably reduce the filtration rate of the water based mud formulated. In the test the filtration rate of the mud is continuously reduced at increased power of the ultrasonic wave and in the length of time the ultrasonic wave is working. Furthermore, the apparent viscosity of the mud is slightly reduced by the action of the ultrasonic wave. With an ultrasonic wave of 20 kHz/850 W acting on the mud for 14 min, the API and HTHP filtration rates of the water based mud are reduced by 26.7% and 27.6% (both maximum reductions) respectively. The thickness of the mud cakes is also reduced by 30%-35% after the action of the ultrasonic wave on the mud. Filtration test on a brine mud shows that the API and HTHP filtration rates are reduced by 29.5% and 32.7% (both maximum reductions) respectively after the action of the ultrasonic wave. Particle size distribution analysis, adsorption experiment and SEM observation show that ultrasonic wave is able to reduce the average size of the bentonite particles and increase the adsorptive capacity of the lignite resin on the particles of bentonite, thereby helping form a denser thin mud cake under the action of pressure differential of the mud. Laboratory studies show that mixing new mud with ultrasonic wave is beneficial to improving the filtration property of lignite resin water based drilling fluids. This performance of ultrasonic wave is the so-called “acoustic cavitation mechanisms”.
A water based mud was formulated with lignite resin and bentonite in laboratory in accordance with the standard SY/T 5679—2017. After agitating the mud with high-speed mixer, the mud was treated with ultrasonic wave to investigate the effects of ultrasonic vibration on the colloidal properties of the mud. The purpose of this test is to find a new way of preparing mud with which the performance of the existing mud additives can be improved. The test results show that ultrasonic vibration can remarkably reduce the filtration rate of the water based mud formulated. In the test the filtration rate of the mud is continuously reduced at increased power of the ultrasonic wave and in the length of time the ultrasonic wave is working. Furthermore, the apparent viscosity of the mud is slightly reduced by the action of the ultrasonic wave. With an ultrasonic wave of 20 kHz/850 W acting on the mud for 14 min, the API and HTHP filtration rates of the water based mud are reduced by 26.7% and 27.6% (both maximum reductions) respectively. The thickness of the mud cakes is also reduced by 30%-35% after the action of the ultrasonic wave on the mud. Filtration test on a brine mud shows that the API and HTHP filtration rates are reduced by 29.5% and 32.7% (both maximum reductions) respectively after the action of the ultrasonic wave. Particle size distribution analysis, adsorption experiment and SEM observation show that ultrasonic wave is able to reduce the average size of the bentonite particles and increase the adsorptive capacity of the lignite resin on the particles of bentonite, thereby helping form a denser thin mud cake under the action of pressure differential of the mud. Laboratory studies show that mixing new mud with ultrasonic wave is beneficial to improving the filtration property of lignite resin water based drilling fluids. This performance of ultrasonic wave is the so-called “acoustic cavitation mechanisms”.
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): 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(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(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(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。
2016, 33(6): 121-126.
doi: 10.3969/j.issn.1001-5620.2016.06.022
摘要：
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现，存地液量越大，一年累积产量越高，与常规的返排率越高产量越高概念恰恰相反，可能与存地液的自发渗吸替油有关。核磁实验结果表明，渗吸替油不同于驱替作用，渗吸过程中小孔隙对采出程度贡献大，而驱替过程中大孔隙对采出程度贡献大，但从现场致密储层岩心孔隙度来看，储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素，探索影响压裂液油水置换的关键影响因素，得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明，各参数对渗吸速度的影响顺序为：界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大，渗吸采收率越大，但是增幅逐渐减小；原油黏度越小，渗吸采收率越大；渗吸液矿化度越大，渗吸采收率越大；当渗吸液中助排剂浓度在0.005%~5%，即界面张力在0.316~10.815 mN/m范围内时，浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明：并不是界面张力越低，采收率越高，而是存在某一最佳界面张力，使地层中被绕流油的数量减少，渗吸采收率达到最高，为油田提高致密储层采收率提供实验指导。
统计长庆油田罗*区块2015年存地液量与油井一年累积产量的关系发现，存地液量越大，一年累积产量越高，与常规的返排率越高产量越高概念恰恰相反，可能与存地液的自发渗吸替油有关。核磁实验结果表明，渗吸替油不同于驱替作用，渗吸过程中小孔隙对采出程度贡献大，而驱替过程中大孔隙对采出程度贡献大，但从现场致密储层岩心孔隙度来看，储层驱替效果明显弱于渗吸效果。通过实验研究了影响自发渗吸效率因素，探索影响压裂液油水置换的关键影响因素，得出了最佳渗吸采出率及最大渗吸速度现场参数。结果表明，各参数对渗吸速度的影响顺序为：界面张力 > 渗透率 > 原油黏度 > 矿化度,岩心渗透率越大，渗吸采收率越大，但是增幅逐渐减小；原油黏度越小，渗吸采收率越大；渗吸液矿化度越大，渗吸采收率越大；当渗吸液中助排剂浓度在0.005%~5%，即界面张力在0.316~10.815 mN/m范围内时，浓度为0.5%（界面张力为0.869 mN/m）的渗吸液可以使渗吸采收率达到最大。静态渗吸结果表明：并不是界面张力越低，采收率越高，而是存在某一最佳界面张力，使地层中被绕流油的数量减少，渗吸采收率达到最高，为油田提高致密储层采收率提供实验指导。
2018, 35(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(3): 21-26.
doi: 10.3969/j.issn.1001-5620.2017.03.004
摘要：
目前长水平井段井壁失稳问题仍是制约国内外页岩气资源钻探开发的重大工程技术难题。为解决龙马溪组页岩长水平井段的井壁失稳问题，采用X射线衍射分析、氦气孔隙体积测试、高压压汞测试、高分辨率场发射扫描电镜、CT扫描、岩石连续刻划强度等实验，分析了龙马溪组页岩微观组构特征及理化特性，探讨了微观组构特征、理化特性对龙马溪组页岩井壁稳定的影响。研究表明：龙马溪页岩富含脆性矿物，黏土矿物以伊蒙混层为主，微纳米孔隙发育，微裂隙呈缝状、近平行分布，敏感性矿物的存在及其层理、微裂缝发育是导致页岩井壁失稳的主要内在因素。为此，针对性地提出了多元协同稳定井壁水基钻井液防塌技术对策，即"强化封堵-适度抑制-合理密度-高效润滑"。应用该技术对策构建了高性能水基钻井液优化配方，评价表明，该体系有较好的封堵性和抑制裂缝扩展的能力。该体系在黄金坝区块2口井三开进行了现场试验。现场试验结果表明，该体系较好地解决了页岩长水平井段的井壁失稳和水平段摩阻较大的问题，为中国采用水基钻井液技术高效钻探开发页岩气资源提供了新的思路及经验。
目前长水平井段井壁失稳问题仍是制约国内外页岩气资源钻探开发的重大工程技术难题。为解决龙马溪组页岩长水平井段的井壁失稳问题，采用X射线衍射分析、氦气孔隙体积测试、高压压汞测试、高分辨率场发射扫描电镜、CT扫描、岩石连续刻划强度等实验，分析了龙马溪组页岩微观组构特征及理化特性，探讨了微观组构特征、理化特性对龙马溪组页岩井壁稳定的影响。研究表明：龙马溪页岩富含脆性矿物，黏土矿物以伊蒙混层为主，微纳米孔隙发育，微裂隙呈缝状、近平行分布，敏感性矿物的存在及其层理、微裂缝发育是导致页岩井壁失稳的主要内在因素。为此，针对性地提出了多元协同稳定井壁水基钻井液防塌技术对策，即"强化封堵-适度抑制-合理密度-高效润滑"。应用该技术对策构建了高性能水基钻井液优化配方，评价表明，该体系有较好的封堵性和抑制裂缝扩展的能力。该体系在黄金坝区块2口井三开进行了现场试验。现场试验结果表明，该体系较好地解决了页岩长水平井段的井壁失稳和水平段摩阻较大的问题，为中国采用水基钻井液技术高效钻探开发页岩气资源提供了新的思路及经验。
2016, 33(3): 67-72.
doi: 10.3969/j.issn.1001-5620.2016.03.014
摘要：
针对顺南区块超深高温高压气井固井面临井底温度高、气层活跃难压稳的问题，研究了胶乳纳米液硅高温防气窜水泥体系。通过将纳米液硅防气窜剂与胶乳防气窜剂复配使用，协同增强水泥浆防气窜性能；不同粒径硅粉复配与加量优化，增强水泥石高温稳定性；无机纤维桥联阻裂堵漏，抑制裂缝延展，提高水泥浆防漏性能和水泥石抗冲击性能。该水泥浆体系具有流动性好、API失水量小于50 mL、直角稠化、SPN值小于1，水泥石具有高温强度稳定性好、胶结强度高、抗冲击能力强的特点。密度为1.92 g/cm3的水泥浆体系在190℃、21 MPa养护30 h后超声波强度逐渐平稳，一界面胶结强度达12.6 MPa；水泥石弹性模量较常规低失水水泥石降低52%，抗冲击强度增加了188%，且受霍普金森杆冲击后仅纵向出现几条未贯穿的裂纹。该高温防气窜水泥浆体系在顺南5-2井和顺南6井成功应用，较好地解决了顺南区块超深气井固井难题。
针对顺南区块超深高温高压气井固井面临井底温度高、气层活跃难压稳的问题，研究了胶乳纳米液硅高温防气窜水泥体系。通过将纳米液硅防气窜剂与胶乳防气窜剂复配使用，协同增强水泥浆防气窜性能；不同粒径硅粉复配与加量优化，增强水泥石高温稳定性；无机纤维桥联阻裂堵漏，抑制裂缝延展，提高水泥浆防漏性能和水泥石抗冲击性能。该水泥浆体系具有流动性好、API失水量小于50 mL、直角稠化、SPN值小于1，水泥石具有高温强度稳定性好、胶结强度高、抗冲击能力强的特点。密度为1.92 g/cm3的水泥浆体系在190℃、21 MPa养护30 h后超声波强度逐渐平稳，一界面胶结强度达12.6 MPa；水泥石弹性模量较常规低失水水泥石降低52%，抗冲击强度增加了188%，且受霍普金森杆冲击后仅纵向出现几条未贯穿的裂纹。该高温防气窜水泥浆体系在顺南5-2井和顺南6井成功应用，较好地解决了顺南区块超深气井固井难题。
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:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2016, 33(6): 10-16.
doi: 10.3969/j.issn.1001-5620.2016.06.002
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
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
