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3 Status Quo of Methods for Evaluating Filtration Performance and Mud Cake Quality of Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
5 Drilling Fluid Technology for “Three High” Wells in Qaidam Basin in Qinghai
6 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
7 A New Fracturing Fluid with Temperature Resistance of 230℃
8 Plugging Micro-fractures to Prevent Gas-cut in Fractured Gas Reservoir Drilling
9 Development of Extreme Pressure Anti-wear Lubricant MPA for Water Base Drilling Fluids
10 Progress in Studying Cement Sheath Failure in Perforated Wells
2 Study and Performance Evaluation of Ultra-High Temperature High Density Oil Based Drilling Fluids
3 Synthesis and Evaluation of A Primary Emulsifier for High Temperature Oil Base Drilling Fluid
4 Progresses in Studying Drilling Fluid Nano Material Plugging Agents
5 Hole Cleaning Technology for Horizontal and Deviated Drilling: Progress Made and Prospect
8 High Performance Water Base Drilling Fluid for Shale Gas Drilling
9 A New Fracturing Fluid with Temperature Resistance of 230℃
10 High Performance Water Base Drilling Fluid for Shale Gas Drilling
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2025, 42(2): 143-154.
doi: 10.12358/j.issn.1001-5620.2025.02.001
Abstract:
Represented by industrial large models, artificial intelligence (AI) technology plays an important role in oil and gas exploration and development. AI not only can effectively reduce costs and improve efficiency, but also opens an important way to promote key technical innovation and upgrading, and to enhance industry competitiveness. By elaborating on the core features and construction modes of industrial large model technology, the current status of the development of industrial large model technology is summarized. Oil and gas large model is one of the important fields of the industrial large models. This paper summarizes the current status of the application of oil and gas large models both at home and abroad, and based on this summarization, the application of oil and gas large models in the drilling and completion field of the domestic oil and gas industry, such as drilling speed enhancement, well trajectory optimization, etc., is prospected. Also in this paper the problems and challenges faced by the application of oil and gas large models in the field of drilling and completion are analyzed, and targeted suggestions proposed, hoping to provide reference and ideas of research and development for the application of oil and gas large models in the field of drilling and completion.
Represented by industrial large models, artificial intelligence (AI) technology plays an important role in oil and gas exploration and development. AI not only can effectively reduce costs and improve efficiency, but also opens an important way to promote key technical innovation and upgrading, and to enhance industry competitiveness. By elaborating on the core features and construction modes of industrial large model technology, the current status of the development of industrial large model technology is summarized. Oil and gas large model is one of the important fields of the industrial large models. This paper summarizes the current status of the application of oil and gas large models both at home and abroad, and based on this summarization, the application of oil and gas large models in the drilling and completion field of the domestic oil and gas industry, such as drilling speed enhancement, well trajectory optimization, etc., is prospected. Also in this paper the problems and challenges faced by the application of oil and gas large models in the field of drilling and completion are analyzed, and targeted suggestions proposed, hoping to provide reference and ideas of research and development for the application of oil and gas large models in the field of drilling and completion.
2025, 42(2): 155-166.
doi: 10.12358/j.issn.1001-5620.2025.02.002
Abstract:
The drilling process of deep-earth Tako-1 well is confronted with a series of extreme conditions such as ultra-high temperature, ultra-high pressure and ultra-high salt. These complex conditions bring great challenges to drilling fluid technology. As the "blood" in drilling process, the performance of drilling fluid is directly related to the success or failure of drilling. This paper systematically introduced the technology of 10,000 meters deep drilling fluid. On the basis of revealing the mechanism of ultra-high temperature and high salt resistance of the key treatment agent of drilling fluid and the mechanism of the plugging material improving the pressure bearing capacity of the fracture-cavity lose layer, through the development of new materials, the construction of new systems and the development of new software, It has formed three key core technologies, which are temperature resistant 240℃ salt-water resistant drilling fluid, temperature resistant 240℃ salt-oil based drilling fluid and malignant fracture- cavity leakage and plugging. It has successfully solved the problems such as the deterioration of drilling fluid's high temperature performance, wellbore instability, friction reduction, malignant leakage and formation pollution, and has been successfully applied in the deep-ground Tako-1 well. It provides key technical support for the successful drilling of the deep subsurface Tako-1 well to 10,910 meters.
The drilling process of deep-earth Tako-1 well is confronted with a series of extreme conditions such as ultra-high temperature, ultra-high pressure and ultra-high salt. These complex conditions bring great challenges to drilling fluid technology. As the "blood" in drilling process, the performance of drilling fluid is directly related to the success or failure of drilling. This paper systematically introduced the technology of 10,000 meters deep drilling fluid. On the basis of revealing the mechanism of ultra-high temperature and high salt resistance of the key treatment agent of drilling fluid and the mechanism of the plugging material improving the pressure bearing capacity of the fracture-cavity lose layer, through the development of new materials, the construction of new systems and the development of new software, It has formed three key core technologies, which are temperature resistant 240℃ salt-water resistant drilling fluid, temperature resistant 240℃ salt-oil based drilling fluid and malignant fracture- cavity leakage and plugging. It has successfully solved the problems such as the deterioration of drilling fluid's high temperature performance, wellbore instability, friction reduction, malignant leakage and formation pollution, and has been successfully applied in the deep-ground Tako-1 well. It provides key technical support for the successful drilling of the deep subsurface Tako-1 well to 10,910 meters.
2025, 42(2): 167-179.
doi: 10.12358/j.issn.1001-5620.2025.02.003
Abstract:
Deep formations in deep water area are developed with fractures and fissures, fluctuations in wellbore pressure during drilling can easily induce ballooning effect which is made complex by the high temperature high pressure (HTHP) downhole environment. Studies on the ballooning effect of fractures in HTHP deep formations in deep water area are important to the control of borehole pressure and the safety of drilling operation. Based on this idea, a temperature-pressure coupling model for HTHP borehole-fracture-formation system is constructed and used to analyze the dynamic response and affecting factors of the ballooning effect. The results of the study show that at high temperatures and low flowrates, the ballooning effect is to some extent inhibited. Increasing the yield point and decreasing the specific heat capacity of a drilling fluid are both beneficial to reducing the amount of the drilling fluid lost. The plastic viscosity of the drilling fluid significantly affects the ballooning effect, and a critical plastic viscosity can be determined at which the amount of the drilling fluid lost is minimum. When drilling in formations with long fractures which have strong deformable capacities, the probability of encountering ballooning effect is higher. Meanwhile, when drilling in formations with small and wide fractures, more severe ballooning effect may be induced. The research results can be used as a theoretical support to the prevention and control of ballooning effect in fractured formation drilling.
Deep formations in deep water area are developed with fractures and fissures, fluctuations in wellbore pressure during drilling can easily induce ballooning effect which is made complex by the high temperature high pressure (HTHP) downhole environment. Studies on the ballooning effect of fractures in HTHP deep formations in deep water area are important to the control of borehole pressure and the safety of drilling operation. Based on this idea, a temperature-pressure coupling model for HTHP borehole-fracture-formation system is constructed and used to analyze the dynamic response and affecting factors of the ballooning effect. The results of the study show that at high temperatures and low flowrates, the ballooning effect is to some extent inhibited. Increasing the yield point and decreasing the specific heat capacity of a drilling fluid are both beneficial to reducing the amount of the drilling fluid lost. The plastic viscosity of the drilling fluid significantly affects the ballooning effect, and a critical plastic viscosity can be determined at which the amount of the drilling fluid lost is minimum. When drilling in formations with long fractures which have strong deformable capacities, the probability of encountering ballooning effect is higher. Meanwhile, when drilling in formations with small and wide fractures, more severe ballooning effect may be induced. The research results can be used as a theoretical support to the prevention and control of ballooning effect in fractured formation drilling.
2025, 42(2): 180-186.
doi: 10.12358/j.issn.1001-5620.2025.02.004
Abstract:
Well Pengshen-6, a six-interval well with a total depth of 9,026 m, is a key exploration well deployed by the PetroChina Southwest Oil & Gasfield Company. The projected reservoir is mainly the Dengying Formation in the Sinian System. The main technical difficulties of the drilling fluid operation include: 1) a thick mudstone with strong water sensitivity in the upper part of the well, 2) coexistence of multiple pressure systems in the same open hole section, 3) poor hole cleaning in the upper extra-large hole because of low annular flow velocity, 4) drilling fluid contamination by long section of salt/gypsum formation, 5) lost circulation resulted from the coexistence of multiple pressure systems, 6) serious acid gas contamination in the well section below the Permian System and difficulties in controlling the rheology of the ultra-high density drilling fluids, 7) difficulties in controlling the rheology and sedimentation stability of the oil-based drilling fluid under ultra-high temperature ultra-high pressure (the bottom hole temperature reaches 216℃ and the bottom hole pressure reaches 150 MPa) in the ultra-deep well section, 8) the broken Dengying Formation in the Sinian System. To deal with these difficulties, three sets of drilling fluid formulations were selected through many laboratory experiments: an organic salt polymer drilling fluid with good encapsulating and inhibitive properties was used to drill the upper section of the well, an organic salt polymer-sulfonate drilling fluid with good high temperature and contamination resisting performances was used to drill the middle section of the well, and an ultra-high temperature-resistant oil-based drilling fluid with good sedimentation stability, rheological properties and cuttings-carrying capacity was used to drill the target zones. In field application of these drilling fluids, the rheology of the drilling fluid in the upper section was under control, and the wellbore was stable; the high-density water-based drilling fluid had good rheology, strong inhibitive and plugging capacities, and strong resistance to salt/calcium/CO2 contamination; the low-density oil-based drilling fluid under ultra-high temperature and ultra-high pressure had controlled rheology, good sedimentation stability and strong anti-collapse capabilities.
Well Pengshen-6, a six-interval well with a total depth of 9,026 m, is a key exploration well deployed by the PetroChina Southwest Oil & Gasfield Company. The projected reservoir is mainly the Dengying Formation in the Sinian System. The main technical difficulties of the drilling fluid operation include: 1) a thick mudstone with strong water sensitivity in the upper part of the well, 2) coexistence of multiple pressure systems in the same open hole section, 3) poor hole cleaning in the upper extra-large hole because of low annular flow velocity, 4) drilling fluid contamination by long section of salt/gypsum formation, 5) lost circulation resulted from the coexistence of multiple pressure systems, 6) serious acid gas contamination in the well section below the Permian System and difficulties in controlling the rheology of the ultra-high density drilling fluids, 7) difficulties in controlling the rheology and sedimentation stability of the oil-based drilling fluid under ultra-high temperature ultra-high pressure (the bottom hole temperature reaches 216℃ and the bottom hole pressure reaches 150 MPa) in the ultra-deep well section, 8) the broken Dengying Formation in the Sinian System. To deal with these difficulties, three sets of drilling fluid formulations were selected through many laboratory experiments: an organic salt polymer drilling fluid with good encapsulating and inhibitive properties was used to drill the upper section of the well, an organic salt polymer-sulfonate drilling fluid with good high temperature and contamination resisting performances was used to drill the middle section of the well, and an ultra-high temperature-resistant oil-based drilling fluid with good sedimentation stability, rheological properties and cuttings-carrying capacity was used to drill the target zones. In field application of these drilling fluids, the rheology of the drilling fluid in the upper section was under control, and the wellbore was stable; the high-density water-based drilling fluid had good rheology, strong inhibitive and plugging capacities, and strong resistance to salt/calcium/CO2 contamination; the low-density oil-based drilling fluid under ultra-high temperature and ultra-high pressure had controlled rheology, good sedimentation stability and strong anti-collapse capabilities.
2025, 42(2): 187-194.
doi: 10.12358/j.issn.1001-5620.2025.02.005
Abstract:
Study on the in-situ wettability of deep reservoir rocks is of great importance to the in-depth understanding of the mechanisms with which a high temperature reservoir is damaged by water block and to the establishment of efficient measures for water block prevention. In this study, cores from a deep reservoir in a block in Bohai (China) were used to in-situ characterize the changes with temperature of the contact angles of different rock surfaces in a nitrogen environment of 20℃ – 200℃ and 8 MPa, and an empirical equation was established for predicting the changes with temperature of the contact angles of reservoir rock surfaces after the oils were washed off the rocks. Using atomic force microscopy, scanning electron microscopy and energy spectrum analysis, the mechanisms with which the changes with temperature of contact angles of rock surfaces were analyzed. The Experimental results showed that the contact angles of the reservoir rock surfaces after washing off the oils were reduced with temperature in different ranges; in 20℃ – 100℃, the rate of change of contact angle is −0.04 °/℃, and −0.24 °/℃ in 100℃-200℃. The adhesion work of water on the rock surfaces generally increases with temperature, the change of which is small though. The adhesion work of water on the rock surfaces with oils increases remarkably with temperature, with a rate of change at 160 ℃ of 155.27%. By measuring the micromorphology and element content of the rock surfaces, it was concluded, considering the physical-chemical characteristics of subcritical water, that the desorption and even the pyrolysis of the hydrocarbons adsorbed on the surfaces of the rocks under the action of subcritical water result in the significant change of the wettability of the oil-adsorbed surfaces of the rocks, and when in contact with the rock surfaces with adsorbed oils, fluids flowing into a well will present more serious water block damage to the reservoir formations. Based on the in-situ characterization of wettability and the physical-chemical properties of subcritical water, some new understandings about the mechanisms with which the wettability of the reservoir rock surfaces changes at elevated temperatures are obtained, and these new understandings are helpful in designing proper water block prevention program in high temperature oil and gas resource development.
Study on the in-situ wettability of deep reservoir rocks is of great importance to the in-depth understanding of the mechanisms with which a high temperature reservoir is damaged by water block and to the establishment of efficient measures for water block prevention. In this study, cores from a deep reservoir in a block in Bohai (China) were used to in-situ characterize the changes with temperature of the contact angles of different rock surfaces in a nitrogen environment of 20℃ – 200℃ and 8 MPa, and an empirical equation was established for predicting the changes with temperature of the contact angles of reservoir rock surfaces after the oils were washed off the rocks. Using atomic force microscopy, scanning electron microscopy and energy spectrum analysis, the mechanisms with which the changes with temperature of contact angles of rock surfaces were analyzed. The Experimental results showed that the contact angles of the reservoir rock surfaces after washing off the oils were reduced with temperature in different ranges; in 20℃ – 100℃, the rate of change of contact angle is −0.04 °/℃, and −0.24 °/℃ in 100℃-200℃. The adhesion work of water on the rock surfaces generally increases with temperature, the change of which is small though. The adhesion work of water on the rock surfaces with oils increases remarkably with temperature, with a rate of change at 160 ℃ of 155.27%. By measuring the micromorphology and element content of the rock surfaces, it was concluded, considering the physical-chemical characteristics of subcritical water, that the desorption and even the pyrolysis of the hydrocarbons adsorbed on the surfaces of the rocks under the action of subcritical water result in the significant change of the wettability of the oil-adsorbed surfaces of the rocks, and when in contact with the rock surfaces with adsorbed oils, fluids flowing into a well will present more serious water block damage to the reservoir formations. Based on the in-situ characterization of wettability and the physical-chemical properties of subcritical water, some new understandings about the mechanisms with which the wettability of the reservoir rock surfaces changes at elevated temperatures are obtained, and these new understandings are helpful in designing proper water block prevention program in high temperature oil and gas resource development.
Study on Wellbore Instability Mechanism of Continental Shale Reservoir in Northeastern Sichuan Basin
2025, 42(2): 217-224.
doi: 10.12358/j.issn.1001-5620.2025.02.009
Abstract:
Shale reservoirs in the Qianfoya continental facies shale reservoirs in northeastern Sichuan collapsed seriously, leading to severe difficulties in drilling a well successfully. To deal with this problem, a systematic analysis of instability characteristics and laboratory experimental evaluation studies were carried out. The analyses of the field data show that the instability mainly occurs in the dark-gray shale layer of the Qianyi member of the Qianfoya Formation, which is characterized by an irregular instability cycle and a coexistence of collapse and lost circulation. Drilling fluids currently used cannot effectively maintain the stability of this easy-to-collapse formation. Laboratory studies have shown that there are significant differences in the wellbore stability among different layers of the Qianyi member of the Qianfoya Formation. Among them, the dark-gray shale layer in the formation has a high content of clay minerals and certain degree of hydration swelling and amphiphilic wetting characteristics. The Qianyi member has strong bedding and the organic matter scratch sliding mirror surface et al. (weak structural surfaces) in the shales are extremely developed. The cementation strength of the shales is weak, resulting in natural breaking of the formation and significant reduction in the rock mechanical properties. Under the action of the drilling fluid and drill string disturbances, the shales peel off and cave in, causing wellbore instability and collapse. This study has presented technical countermeasures for safe and successful drilling, such as avoiding the formations that are prone to collapse, providing references for horizontal well drilling for continental shale oil and gas in the future.
Shale reservoirs in the Qianfoya continental facies shale reservoirs in northeastern Sichuan collapsed seriously, leading to severe difficulties in drilling a well successfully. To deal with this problem, a systematic analysis of instability characteristics and laboratory experimental evaluation studies were carried out. The analyses of the field data show that the instability mainly occurs in the dark-gray shale layer of the Qianyi member of the Qianfoya Formation, which is characterized by an irregular instability cycle and a coexistence of collapse and lost circulation. Drilling fluids currently used cannot effectively maintain the stability of this easy-to-collapse formation. Laboratory studies have shown that there are significant differences in the wellbore stability among different layers of the Qianyi member of the Qianfoya Formation. Among them, the dark-gray shale layer in the formation has a high content of clay minerals and certain degree of hydration swelling and amphiphilic wetting characteristics. The Qianyi member has strong bedding and the organic matter scratch sliding mirror surface et al. (weak structural surfaces) in the shales are extremely developed. The cementation strength of the shales is weak, resulting in natural breaking of the formation and significant reduction in the rock mechanical properties. Under the action of the drilling fluid and drill string disturbances, the shales peel off and cave in, causing wellbore instability and collapse. This study has presented technical countermeasures for safe and successful drilling, such as avoiding the formations that are prone to collapse, providing references for horizontal well drilling for continental shale oil and gas in the future.
2025, 42(2): 225-232.
doi: 10.12358/j.issn.1001-5620.2025.02.010
Abstract:
Horizontal drilling of deep buried coal-bed methane in Jizhong area has been faced with several difficulties and challenges such as quite limited data for reference, many geologic uncertainties, thin coal-bed layers which are easy to collapse and have difficulties in trajectory control, as well as high risks of pipe sticking etc. Extensive studies on the characteristics of the deep buried coal-bed reservoirs have concluded that the stability of the borehole wall in the coal-bed formations is controlled both by mechanical factors and physio-chemical factors, the key points of technology in solving this problem is to improve the plugging capacity and inhibitive capacity of the drilling fluid. A drilling fluid with high plugging capacity was formulated to drill the coal-bed formations by treating a compounded salt drilling fluid with rigid micro- and nano-plugging agents and deformable plugging agents. Laboratory experiments on the drilling fluid with hot rolling test, sand-bed plugging test and ceramic filter plugging test show that this drilling fluid has inhibitive capacity and plugging capacity better than those of KCl polymer drilling fluids and compounded salt drilling fluids. This drilling fluid has been used in drilling the well Xintan-1H and proved that the plugging agents have good compatibility with other additives and no negative effect on the properties of the drilling fluid. The addition of the plugging agent into the drilling fluid greatly reduced the API filtration rate and effectively maintained the borehole wall stability. In drilling the 1,270 m long horizontal section, the coal-bed formation, after being soaked by the drilling fluid for 23 days, showed no tendency of borehole wall collapse. Cuttings out of hole have regular shapes and sizes, and from the shale shakers only mudstone sloughing was observed. Tripping into the hole and out of hole were both smoothly conducted. The use of this new drilling fluid has effectively solved the borehole wall destabilization problem encountered in deep horizontal coal-bed methane drilling and ensured the success of drilling. The application of this technology will help achieve efficient and large-scale development and breakthrough in deep buried coal-bed methane drilling and exploration.
Horizontal drilling of deep buried coal-bed methane in Jizhong area has been faced with several difficulties and challenges such as quite limited data for reference, many geologic uncertainties, thin coal-bed layers which are easy to collapse and have difficulties in trajectory control, as well as high risks of pipe sticking etc. Extensive studies on the characteristics of the deep buried coal-bed reservoirs have concluded that the stability of the borehole wall in the coal-bed formations is controlled both by mechanical factors and physio-chemical factors, the key points of technology in solving this problem is to improve the plugging capacity and inhibitive capacity of the drilling fluid. A drilling fluid with high plugging capacity was formulated to drill the coal-bed formations by treating a compounded salt drilling fluid with rigid micro- and nano-plugging agents and deformable plugging agents. Laboratory experiments on the drilling fluid with hot rolling test, sand-bed plugging test and ceramic filter plugging test show that this drilling fluid has inhibitive capacity and plugging capacity better than those of KCl polymer drilling fluids and compounded salt drilling fluids. This drilling fluid has been used in drilling the well Xintan-1H and proved that the plugging agents have good compatibility with other additives and no negative effect on the properties of the drilling fluid. The addition of the plugging agent into the drilling fluid greatly reduced the API filtration rate and effectively maintained the borehole wall stability. In drilling the 1,270 m long horizontal section, the coal-bed formation, after being soaked by the drilling fluid for 23 days, showed no tendency of borehole wall collapse. Cuttings out of hole have regular shapes and sizes, and from the shale shakers only mudstone sloughing was observed. Tripping into the hole and out of hole were both smoothly conducted. The use of this new drilling fluid has effectively solved the borehole wall destabilization problem encountered in deep horizontal coal-bed methane drilling and ensured the success of drilling. The application of this technology will help achieve efficient and large-scale development and breakthrough in deep buried coal-bed methane drilling and exploration.
2025, 42(2): 233-238.
doi: 10.12358/j.issn.1001-5620.2025.02.011
Abstract:
In studying the standards concerning sodium formate and potassium formate as drilling fluid additives, the major problems existed in and factors affecting the measurement of the concentrations of formates were analyzed, and a best detection method was screened out through optimization of many methods presently in use. Methods for sodium formate detection presently in use generally give results that are higher than the true values and are sometimes higher than 100%. To solve this problem, several methods such as infrared spectrum measurement were used to detect the content of sodium formate in a drilling fluid, and it was found that the sodium formate products presently in use are all manufactured by byproduct methods, and contain organic impurities such as pentaerythritol. The method that found suitable for the detection of sodium formate is the burning titration method, which was optimized through experiment. It was found in laboratory experiment that the introduction of phenolphthalein when washing and transferring the burned product causes the titration endpoint to delay and the result obtained is thus higher than the true value. By improving the washing and transferring process, this negative effect was eliminated. It was also found that sodium thiosulfate titration method is suitable for the detection of potassium formate. Increasing the content of the potassium ions helps obtain more accurate results, eliminating the disadvantages of the old methods in which the content of potassium formate is calculated only from the content of formate radical and it is thus unable to identify the low-cost formate adulteration. The achievements of this study have been introduced into the standard T/CPSI 06401—2024 named “Weighting Agent for Drilling Fluid—Formates”, which was issued and implemented in April of 2024.
In studying the standards concerning sodium formate and potassium formate as drilling fluid additives, the major problems existed in and factors affecting the measurement of the concentrations of formates were analyzed, and a best detection method was screened out through optimization of many methods presently in use. Methods for sodium formate detection presently in use generally give results that are higher than the true values and are sometimes higher than 100%. To solve this problem, several methods such as infrared spectrum measurement were used to detect the content of sodium formate in a drilling fluid, and it was found that the sodium formate products presently in use are all manufactured by byproduct methods, and contain organic impurities such as pentaerythritol. The method that found suitable for the detection of sodium formate is the burning titration method, which was optimized through experiment. It was found in laboratory experiment that the introduction of phenolphthalein when washing and transferring the burned product causes the titration endpoint to delay and the result obtained is thus higher than the true value. By improving the washing and transferring process, this negative effect was eliminated. It was also found that sodium thiosulfate titration method is suitable for the detection of potassium formate. Increasing the content of the potassium ions helps obtain more accurate results, eliminating the disadvantages of the old methods in which the content of potassium formate is calculated only from the content of formate radical and it is thus unable to identify the low-cost formate adulteration. The achievements of this study have been introduced into the standard T/CPSI 06401—2024 named “Weighting Agent for Drilling Fluid—Formates”, which was issued and implemented in April of 2024.
2025, 42(2): 239-246.
doi: 10.12358/j.issn.1001-5620.2025.02.012
Abstract:
As the important engineering of China’s “energy resource supply guarantee”, underground gas storage (UGS) has three functions, which are seasonal peak shaving, emergency response to accidents and national energy strategic reserve. The formations into which the UGSs have been built in north China generally have such characteristics as complex geological conditions, deep buried depths, high bottom hole temperatures, narrow density windows, high fluid loss risks, long intervals that need to be cemented in one job, as well as rigorous requirements for borehole integrity because of long-term sealing of the wellbores, etc. Common cement slurries do not have the required properties to satisfy the requirements of well cementing under these conditions. To solve these problems, a multi-functional active toughening material HFOC was developed through extensive experimental research. The general performance and the toughing mechanisms of tough cement slurries were investigated. Using HFOC, a tough cement slurry was formulated for use in cementing UGS wells, and the well cementing techniques, such as prestressed well cementing, were also optimized for the use of the new cement slurry. Laboratory experimental results show that the tough cement slurry has its density adjustable between 1.88 g/cm3 and 1.92 g/cm3, the thickening time of the cement slurry is adjustable and the cement slurry shows right-angle thickening behavior, the top and bottom density difference of the cement slurry is zero, no free water is observed in the cement slurry, the API filter loss is less than 50 mL, the 7-day elastic modulus is less than 6.48 GPa, and the 80℃/24-hour compressive strength is greater than 14 MPa. The toughening mechanisms of the tough cement slurry are investigated from both physical and chemical aspects. It was found that tetracalcium aluminoferrite (C4AF) in a cement has positive effects on the toughness and mechanical properties of the set cement; an increase in the content of C4AF in the cement can better prevent the extension of the micro fractures in the set cement, thereby improving the sealing integrity of the cement sheath. This technology has been successfully applied in cementing the production casing in the UGS drilling in north China, and the quality of the well cementing job has satisfied the requirements of UGS construction. This technology can be used as a technical support and reference for the cementing other UGSs.
As the important engineering of China’s “energy resource supply guarantee”, underground gas storage (UGS) has three functions, which are seasonal peak shaving, emergency response to accidents and national energy strategic reserve. The formations into which the UGSs have been built in north China generally have such characteristics as complex geological conditions, deep buried depths, high bottom hole temperatures, narrow density windows, high fluid loss risks, long intervals that need to be cemented in one job, as well as rigorous requirements for borehole integrity because of long-term sealing of the wellbores, etc. Common cement slurries do not have the required properties to satisfy the requirements of well cementing under these conditions. To solve these problems, a multi-functional active toughening material HFOC was developed through extensive experimental research. The general performance and the toughing mechanisms of tough cement slurries were investigated. Using HFOC, a tough cement slurry was formulated for use in cementing UGS wells, and the well cementing techniques, such as prestressed well cementing, were also optimized for the use of the new cement slurry. Laboratory experimental results show that the tough cement slurry has its density adjustable between 1.88 g/cm3 and 1.92 g/cm3, the thickening time of the cement slurry is adjustable and the cement slurry shows right-angle thickening behavior, the top and bottom density difference of the cement slurry is zero, no free water is observed in the cement slurry, the API filter loss is less than 50 mL, the 7-day elastic modulus is less than 6.48 GPa, and the 80℃/24-hour compressive strength is greater than 14 MPa. The toughening mechanisms of the tough cement slurry are investigated from both physical and chemical aspects. It was found that tetracalcium aluminoferrite (C4AF) in a cement has positive effects on the toughness and mechanical properties of the set cement; an increase in the content of C4AF in the cement can better prevent the extension of the micro fractures in the set cement, thereby improving the sealing integrity of the cement sheath. This technology has been successfully applied in cementing the production casing in the UGS drilling in north China, and the quality of the well cementing job has satisfied the requirements of UGS construction. This technology can be used as a technical support and reference for the cementing other UGSs.
2025, 42(2): 247-254.
doi: 10.12358/j.issn.1001-5620.2025.02.013
Abstract:
In coal gasification and shale gas in-situ development, the bottoms of the wellbores are in an ultra-high temperature xerothermic environment, which is of great challenge to the thermal stability of the cement sheaths. To deal with this challenge, the deterioration of set silicate cement long exposed to 600℃ xerothermic environment was studied, and the microstructure features and hydration products were analyzed. It was found in the study that the compressive strength of the common set silicate cement in this environment decreased significantly, and the porosity and permeability of the set cement increased, the microstructure of the set cement turned from gel structure to granular structure, and the calcium hydroxide and C—S—H gel disappeared and changed into dicalcium silicate-γ, larnite and brownmillerite. The porosity and permeability of set sanded cement increased with time of aging, and the gel structure almost all disappeared and the structure of the set cement was finally mainly granular, cotton-like and needle-like crystal. Meanwhile, calcium hydroxide and C—S—H gel disappeared and changed into a large amount of larnite. Quartz, on the other hand, took part in the hydration reaction less intensively and didn’t have obvious effects on inhibiting the damage of set cement. These results show that silicate cement cannot satisfy the sealing requirement in in-situ development of shale gas in high temperature xerothermic environment. In this study, preliminary exploration was conducted on the adaptability of two cements, which are SCKL modified silicate cement and aluminate cement, to a long term 600℃ xerothermic environment, and it was found that aluminate cement can hopefully be used as a cementing material for in-situ development in ultra-high temperature xerothermic environment, further studies need to be conducted to improve its overall properties though. The results of the study have provided references to the selection of cement slurries suitable for cementing the formations in which in-situ development of shale gas and coal gasification are conducted, to the improvement of the overall properties of the set cement, and to the development of new cementing materials for high temperature high pressure well cementing.
In coal gasification and shale gas in-situ development, the bottoms of the wellbores are in an ultra-high temperature xerothermic environment, which is of great challenge to the thermal stability of the cement sheaths. To deal with this challenge, the deterioration of set silicate cement long exposed to 600℃ xerothermic environment was studied, and the microstructure features and hydration products were analyzed. It was found in the study that the compressive strength of the common set silicate cement in this environment decreased significantly, and the porosity and permeability of the set cement increased, the microstructure of the set cement turned from gel structure to granular structure, and the calcium hydroxide and C—S—H gel disappeared and changed into dicalcium silicate-γ, larnite and brownmillerite. The porosity and permeability of set sanded cement increased with time of aging, and the gel structure almost all disappeared and the structure of the set cement was finally mainly granular, cotton-like and needle-like crystal. Meanwhile, calcium hydroxide and C—S—H gel disappeared and changed into a large amount of larnite. Quartz, on the other hand, took part in the hydration reaction less intensively and didn’t have obvious effects on inhibiting the damage of set cement. These results show that silicate cement cannot satisfy the sealing requirement in in-situ development of shale gas in high temperature xerothermic environment. In this study, preliminary exploration was conducted on the adaptability of two cements, which are SCKL modified silicate cement and aluminate cement, to a long term 600℃ xerothermic environment, and it was found that aluminate cement can hopefully be used as a cementing material for in-situ development in ultra-high temperature xerothermic environment, further studies need to be conducted to improve its overall properties though. The results of the study have provided references to the selection of cement slurries suitable for cementing the formations in which in-situ development of shale gas and coal gasification are conducted, to the improvement of the overall properties of the set cement, and to the development of new cementing materials for high temperature high pressure well cementing.
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。
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(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。
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。
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。
2018, 35(3): 8-16.
doi: 10.3969/j.issn.1001-5620.2018.03.002
摘要：
解决环境污染问题是改善钻井液的关键，开发环保型抗高温降滤失剂是当前研究的重要领域之一。概述了国内外环保型降滤失剂的研究进展，对国内外在环保型降滤失剂研制中所使用的原材料及产品性能，以及中国抗温改性天然高分子降滤失剂的发展近况进行了介绍。天然高分子降滤失剂是通过对淀粉、纤维素及木质素等天然高分子材料进行改性以提高其抗温、抗盐能力，使其可以应用于井温更高的深井钻探中。目前，中国环保型降滤失剂普遍可以应用到150℃的高温中，部分抗温能力可达到180℃却未能推广使用。通过对现有降滤失剂的研究，分析其抗高温的作用机理，探寻能有效提高抗温能力的单体分子结构及发挥作用的功能基团，例如磺酸基团、内酰胺基团等，以期对环保型抗高温降滤失剂的研制起到一定的指导和参考作用，加快环保型抗高温降滤失剂的发展。
解决环境污染问题是改善钻井液的关键，开发环保型抗高温降滤失剂是当前研究的重要领域之一。概述了国内外环保型降滤失剂的研究进展，对国内外在环保型降滤失剂研制中所使用的原材料及产品性能，以及中国抗温改性天然高分子降滤失剂的发展近况进行了介绍。天然高分子降滤失剂是通过对淀粉、纤维素及木质素等天然高分子材料进行改性以提高其抗温、抗盐能力，使其可以应用于井温更高的深井钻探中。目前，中国环保型降滤失剂普遍可以应用到150℃的高温中，部分抗温能力可达到180℃却未能推广使用。通过对现有降滤失剂的研究，分析其抗高温的作用机理，探寻能有效提高抗温能力的单体分子结构及发挥作用的功能基团，例如磺酸基团、内酰胺基团等，以期对环保型抗高温降滤失剂的研制起到一定的指导和参考作用，加快环保型抗高温降滤失剂的发展。
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。
2020, 37(6): 685-693.
doi: 10.3969/j.issn.1001-5620.2020.06.002
Abstract:
2016, 33(5): 1-8.
doi: 10.3969/j.issn.1001-5620.2016.05.001
Abstract:
2016, 33(6): 1-9.
doi: 10.3969/j.issn.1001-5620.2016.06.001
Abstract:
2017, 34(1): 1-8.
doi: 10.3969/j.issn.1001-5620.2017.01.001
Abstract:
2016, 33(6): 45-50.
doi: 10.3969/j.issn.1001-5620.2016.06.008
Abstract:
2016, 33(1): 6-10.
doi: 10.3969/j.issn.1001-5620.2016.01.002
Abstract:
2018, 35(1): 101-104.
doi: 10.3969/j.issn.1001-5620.2018.01.019
Abstract:
2017, 34(1): 16-22.
doi: 10.3969/j.issn.1001-5620.2017.01.003
Abstract:
2018, 35(1): 34-37.
doi: 10.3969/j.issn.1001-5620.2018.01.006
Abstract:
2016, 33(6): 10-16.
doi: 10.3969/j.issn.1001-5620.2016.06.002
Abstract:
Governed by：
China National Petroleum Corporation Ltd
China National Petroleum Corporation Ltd
Sponsored by：
CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
CNPC Bohai Drilling Engineering Co. LtdPetroChina Huabei Oilfield Company
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：
Editorial Office of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province
Editorial Office 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
CN 12-1486/TE
ISSN 1001-5620
