Current Articles

2025, Volume 42,  Issue 2

column
Cover Catalogue
  Previous Issue
Display Method:
FORUM
The Status-Quo of the Application and Research and Prospect of Oil and Gas Large Model in Well Drilling and Completion Industry
WU Yaohui, LIU Meiquan, LI Xuesong, LIU Changyue
2025, 42(2): 143-154. doi: 10.12358/j.issn.1001-5620.2025.02.001
Abstract(70) HTML (19) PDF (4131KB)(31)
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.
DRILLING FLUID
Drilling fluid technology for deep subsurface Tako-1 well
SUN Jinsheng, WANG Jianhua
2025, 42(2): 155-166. doi: 10.12358/j.issn.1001-5620.2025.02.002
Abstract(71) HTML (18) PDF (5900KB)(46)
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 Dynamic Response Characteristics of Ballooning Effect in Deep Fractured High Temperature High Pressure Formations in Deep Water Drilling
WU Yanhui, HUANG Honglin, LUO Ming, LI Wentuo, MA Chuanhua, DAI Rui, LI Jun
2025, 42(2): 167-179. doi: 10.12358/j.issn.1001-5620.2025.02.003
Abstract(52) HTML (21) PDF (4546KB)(18)
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.
Drilling Fluid Technology for the Deepest Vertical Well in Asia – The Ultra-Deep Well Pengshen-6
XU Yi, HE Tao, WANG Jun, OU Meng, YAN Fushou, ZHOU Huaan, HUANG Xuyao
2025, 42(2): 180-186. doi: 10.12358/j.issn.1001-5620.2025.02.004
Abstract(60) HTML (13) PDF (2066KB)(34)
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.
Mechanisms of Water Block Damage of High Temperature Reservoirs Based on In-situ Characterization of Wettability and Subcritical Water Characteristics
SHAN Kai, QIU Zhengsong, CHENG Zheng, YANG Mengtao, LI Kai, ZHONG Hanyi, REN Xiaoxia
2025, 42(2): 187-194. doi: 10.12358/j.issn.1001-5620.2025.02.005
Abstract(43) HTML (13) PDF (4011KB)(14)
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 Wellbore Instability Mechanism of Continental Shale Reservoir in Northeastern Sichuan Basin
GAO Shuyang, BO Kehao, ZHANG Yayun, GAO Hong, HUANGFU Jinglong
2025, 42(2): 217-224. doi: 10.12358/j.issn.1001-5620.2025.02.009
Abstract(54) HTML (17) PDF (2755KB)(27)
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.
High Plugging Capacity Drilling Fluid Technology for Deep Buried Coal-Bed Methane Drilling in Jizhong Area
LUO Yucai, YU Huamin, SUN Hao, YU Jiantao, FENG Dan, LIU Fei
2025, 42(2): 225-232. doi: 10.12358/j.issn.1001-5620.2025.02.010
Abstract(45) HTML (10) PDF (3188KB)(25)
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.
Methods of Measuring Formate Content in Drilling Fluids
ZHANG Xiaoguang, YANG Junzhen, WANG Ping, LI Bin, LI Huimin, CHEN Leixu, ZHANG Lingying
2025, 42(2): 233-238. doi: 10.12358/j.issn.1001-5620.2025.02.011
Abstract(37) HTML (11) PDF (2126KB)(21)
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.
CEMENTING FLUID
The Toughening Mechanisms of Tough Cement Slurries for the Underground Gas Storage in North China
LI Lichang, CAO Hongchang, GAO Yang, LIU Jingli, MA Jun, HUANG Jian, LIU Junhua, SUN Wenzhao
2025, 42(2): 239-246. doi: 10.12358/j.issn.1001-5620.2025.02.012
Abstract(43) HTML (12) PDF (3064KB)(19)
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.
Thermal Damage of Set Silicate Cement in Ultra-High Temperature Xerothermic Environment
LI Xiaojiang, WANG Yueyang, XIAO Jingnan, WEI Haoguang, YANG Ruiyue
2025, 42(2): 247-254. doi: 10.12358/j.issn.1001-5620.2025.02.013
Abstract(35) HTML (8) PDF (2943KB)(14)
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.
Synergistic Effects of Tricalcium Aluminate and Gypsum on Performance of Oil Well Cement Slurries
DAI Dan, WANG Yixin, ZOU Yiwei, SUN Chao, MA Ying, SONG Xinjun
2025, 42(2): 255-261. doi: 10.12358/j.issn.1001-5620.2025.02.014
Abstract(33) HTML (11) PDF (2923KB)(11)
Abstract:
To better control the quality of oil well cement, class G cement clinkers with different contents of tricalcium aluminate (C3A) were mixed with different kinds of gypsums, and study was conducted on the synergistic effects of C3A and gypsum on the gelling time, thickening property, compressive strength, permeability and hydration products of the cement at 80℃. It was found that at this temperature, the higher the C3A content, the shorter the gelling time and thickening time of the cement. High C3A content is beneficial to the enhancement of the early strength of the set cement, the disadvantage of this is that the strength of the set cement in later stage will have a negative growth. To avoid this deficiency, the C3A content in a cement should be controlled to less than 3%. Gypsum in the cement helps extend the gelling time of the cement, in this way the dihydrate gypsum is better than bassanite, and bassanite is in turn better than anhydrite. Compared with bassanite and anhydrite, dihydrate gypsum can extend the thickening time of the H42L (a retarder) treated cement slurry much longer, and the use of dihydrate gypsum is much more beneficial to the development of the compressive strength of set cement. At 80℃, the synergistic action between C3A and dihydrate gypsum promoted the hydration of calcium silicate’s early stage mineral phase, the hydration product of C3A was mainly C3AH6, the amount of which produced was closely related to the content of C3A in the cement and the types of gypsum. The results of this study are of theoretical and referential importance to the control of the quality stability of oil well cement and to the quality improvement of well cementing operation.
FRACTUREING FLUID & ACIDIZING FLUID
Rheology of a Viscoelastic Hexameric Cationic Surfactant Micellar Fracturing Fluid
BIN Yujie, HAN Xiaoyang, TIAN Zhenrui, WU Zhiying, ZHANG Siqi, FANG Bo, LU Yongjun
2025, 42(2): 262-274. doi: 10.12358/j.issn.1001-5620.2025.02.015
Abstract(26) HTML (8) PDF (3044KB)(11)
Abstract:
In developing new viscoelastic (VES) thickening agents and new fracturing fluids, several raw materials, including ethylenediamine, epichlorohydrin, erucamide propyl dimethyl tertiary amine (PKO-E) and sodium chloroacetate were used to first produce tetrameric cationic surfactant (TET), hexameric cationic surfactant (HET) and tetrameric zwitterionic surfactant (TZI), and the surfactants were then reacted with counterion salts potassium bromide (KBr) and sodium salicylate (NaSal) to produce a viscoelastic micelle, from which four VES fracturing fluids were formulated. The effects of the types and concentrations of the counterion salts and the concentrations of the surfactants on the rheology of the micellar systems were investigated, and the steady-state viscosity, flow curve, viscoelasticity, thixotropy, thermal-thixotropy and the modulus-temperature curve of the viscoelastic HET/KBr micellar system, as well as the optimum composition of the HET/KBr micellar system were obtained. A four-parameter rheological dynamics equation and a four-parameter viscosity-temperature equation were developed to describe the change of viscosity with shearing time and the temperature thixotropy of the HET/KBr system, respectively. The rheological differences among the micellar systems HET/KBr, HET/NaSal, TET/KBr and TZI/KBr were also understood. The effects of NaOH on delaying the generation of micelles in the HET/HSal system were preliminarily investigated.
Preparation and Evaluation of a Temporary Plugging Organosilicon Diverting Agent for Fracturing Fluids
LIU Yi, YU Chenglin, LI Yunzi, JIANG Ximei, YU Yangyang, WU Jun, LIU Jing
2025, 42(2): 275-282. doi: 10.12358/j.issn.1001-5620.2025.02.016
Abstract(31) HTML (9) PDF (5456KB)(10)
Abstract:
Particulate temporary plugging agents presently used in fracturing fluids are mostly rigid, and deficiencies exist in using these plugging agents, such as insignificant pressure buildup, short pressure stabilization time and inability to effectively transfer stress etc. To deal with these problems, an organosilicon hydrogel named LYB was developed through micellar polymerization with main raw materials acrylamide and N,N-methylene bis-acrylamide, as well as an organosilicon hydrophobic monomer. The effects of the monomer concentration, the hydrophobic monomer, the polymerization method and the polymerization conditions on the LYB hydrogel were investigated, and FTIR and element analysis method were used to characterize the LYB hydrogel. The experimental results show that the optimum conditions for the synthesis of the LYB hydrogel are as follows: the concentrations of the water soluble monomers, the organosilicon, the crosslinking agent and the initiator are 8 – 10%, 2%, 0.02% and 0.2%, respectively, the reaction temperature is 50 – 60 °C, and the reaction time is 6 – 8 h. Laboratory evaluation of the LYB hydrogel shows that compared with the commonly used rigid particulates, the LYB hydrogel has higher shear strength, better salt resistance and elasticity. From the fracturing job curves and microseismical monitoring results, it can be seen that when the LYB temporary plugging agents are in place, the in-situ pressure is increased by 7 – 8 MPa. After temporarily plugging the fractures, the flowrate at the same job pressure is reduced by 1.5 m3/min. Using downhole microseisms, the effectiveness of the fracture diversion by the LYB hydrogel is further verified.

Website Copyright Drilling Fluid & Completion Fluid津ICP备13002319号-1

Address：Editorial Office of Drilling Fluid and Completion Fluid, Bohai Drilling Engineering Institute, Yanshan South Road, Renqiu City, Hebei Province

Tel：（0317）2725487　2722354Email：zjyywjy@126.comPost Code：062552

Supported by: Beijing Renhe Information Technology Co., Ltd.