钻井液与完井液

Abstract:
As oil and gas exploration gradually extends to deep and complex formation drilling as well as unconventional oil and gas reservoirs, drilling fluids in high temperature high pressure downhole environment are faced with dual severe challenges of wellbore instability and rapid deterioration of their own properties. Nano-silica (SiO₂) exhibits great potential in enhancing the properties of a drilling fluid, its inherent agglomeration effect, however, restricts its application. To fully exert the nano-advantages of SiO₂ and to endow it with specific functions, it is necessary to render surface modification to SiO₂. This paper systematically reviews the mechanism and research progress of modified nano-SiO₂ in drilling fluids, focusing on the multiple synergistical mechanisms of nano-SiO₂ in physical plugging, chemical inhibition and interfacial regulation in wellbore stabilization. The application of modified nano-SiO₂ as the core additive in optimizing drilling fluid rheology, controlling fluid loss and lubricating is also systematically summarized. The cutting-edge research advances of modified nano-SiO₂-based smart responsive composite materials are comprehensively reviewed, and the huge potential of their smart behaviors, such as temperature responsiveness, in achieving formation-adaptative plugging and performance regulation are revealed. Although breakthroughs have been made currently in surface modification technology, property regulation mechanism and multifield applications of modified nano-SiO₂, demonstrating broad industrialization prospects, bottlenecks still need to be urgently broken through in the mechanical and large-scale preparation as well as long-term stabilization of modified nano-SiO₂ materials. Strength should be given in future research to solving the problems aforementioned to push forward the large-scale application of modified nano-SiO₂ in drilling fluids.

DRILLING FLUID

Synthesis of Ultra-High Temperature Zwitterionic Polymer Fluid Loss Reducer for Water-Based Drilling Fluids

Wang Yiting, Li Daqi, Yang Fan, Shi Nan, Li Xuan

2026, 43(4): 445-451. doi: 10.12358/j.issn.1001-5620.2026.04.002

Abstract(39) HTML (15) PDF (3185KB)(10)

Abstract:
Polymer filter loss reducers presently used in water-based drilling fluids have a problem of insufficient functional group density. To address this problem, a multifunction monomer A with hydroxyl and sulfonic acid group is used to replace the single-functional group monomer AMPS to react with AA, DMDAAC and polyether monomer H. The product of the free-radical copolymerization reaction is a quaterpolymer filter loss reducer. The ultra-high-temperature performance, salt-resistance, filtration control property and compatibility of this filter loss reducer was systematically investigated. The results show that after aging at 240 ℃ for 16 hours, a freshwater mud, a saltwater mud and a saturated saltwater mud, each containing 2% of the synthesized filter loss reducer, have API fluid losses that were reduced by 80%. Among these drilling fluids, the freshwater mud, which contains 2% of the filter loss reducer, still exhibits filtration control capacity even after being aged at 260 ℃. This filter loss reducer is excellently compatible with sulfonated lignite (SMC), and the use of the filter loss reducer with SMC makes the drilling fluid rheology easy to control; a drilling fluid treated with the filter loss reducer and SMC, after being aged at 240 ℃ for 16 hours, has an API filter loss of only 1.8 mL and an HTHP filter loss of only 24 mL. The research shows that the quaterpolymer filter loss reducer exhibits both excellent high-temperature stability and salt contamination resistant capacity, making it suitable for use in complex drilling conditions, such as drilling ultra-high-temperature formations and salt and gypsum formations. It provides a theoretical basis and technical support for the molecular design of ultra-high-temperature polymer filter loss reducer and the formulation of ultra-high-temperature saltwater-based drilling fluid system.

Preparation and Performance Evaluation of Novel Organoclay for Oil-based Drilling Fluids

Ding Fan, Shi Nan, Wang Xianguang, Zhang Yubin, Han Xiuzhen, Li Daqi, Zhao Jie, Chen Yongqiang

2026, 43(4): 452-459. doi: 10.12358/j.issn.1001-5620.2026.04.003

Abstract(33) HTML (13) PDF (5195KB)(7)

Abstract:
To improve the rheological performance of oil-based drilling fluids at high temperatures, bentonite was used as the matrix to comparatively investigate the effects of head-group structures, including quaternary ammonium, pyridine, and imidazole groups, and alkyl chain length on the microstructure and high-temperature rheological performance of organoclays. FT-IR, XRD, and thermogravimetric analyses showed that the modifiers were intercalated into the bentonite interlayers through electrostatic adsorption of the head groups and hydrophobic interactions among the tail chains, while some were physically adsorbed onto the surface. The maximum physical adsorption/electrostatic intercalation loadings of CTAC, OPB, CPB, OMB, and CMB on bentonite were 0.37/0.56 mmol/g, 0.021/0.63 mmol/g, 0.44/0.28 mmol/g, 0.016/0.54 mmol/g, and 0.17/0.48 mmol/g, respectively. Molecular dynamics simulations indicated that the absolute value of the electrostatic energy of CPB increased from 87.42 kcal/mol to 88.17 kcal/mol under high-temperature conditions, suggesting enhanced electrostatic interactions between CPB and bentonite. Rheological experiments showed that, with respect to head-group structures, heterocyclic-group-modified organoclays exhibited better high-temperature rheological performance, with the AV and YP of OBen-3 reaching 19 mPa·s and 3 Pa, respectively, after hot rolling at 240 ℃. As the alkyl chain length increased, the rheological performance of the organoclays improved markedly. After hot rolling at 240 ℃ in the all-oil-based drilling fluid system, OBen-3 exhibited AV, PV, and YP values of 90 mPa·s, 85 mPa·s, and 5 Pa, respectively, demonstrating good compatibility and high-temperature rheological performance. Moreover, the high-temperature and high-pressure filtration loss of OBen-3 was only 3.2 mL, indicating good filtration-loss control performance. In addition, OBen-3 exhibited favorable high-temperature rheological performance and effective high-temperature and high-pressure filtration-loss control in the water-in-oil system. This study suggests that introducing rigid structures with long alkyl chains can enhance intermolecular and interfacial interactions within the organoclay structure, thus significantly improving the high-temperature rheological performance of organoclays. These findings provide insights into the development of organoclays for high-temperature-resistant oil-based drilling fluids.

High-performance Brine-based Drilling Fluid System for Extended-reach Horizontal Wells

Wen Fei, Xu Mingbiao, Xu Peng, Li Zongwei, Ke Dian

2026, 43(4): 460-469. doi: 10.12358/j.issn.1001-5620.2026.04.004

Abstract(36) HTML (11) PDF (8611KB)(12)

Abstract:
To address the technical bottlenecks of difficult hole cleaning, high friction and torque, and poor wellbore stability in water-based drilling fluids during extended-reach well drilling, a high-performance brine-based drilling fluid system was developed. Based on a potassium chloride-formate composite brine, the system incorporated the self-developed star-shaped polyamine inhibitor HIB and nano-composite friction reducer SLIP, and optimized flow-pattern regulation and multi-stage plugging technologies, achieving synergistic improvements in inhibition, lubrication, cuttings-carrying capacity, and stability performance. Comprehensive comparisons with conventional KCl polymer systems, commercial polyamine systems, and lubricants showed that HIB exhibited significantly better inhibition than conventional polyamine inhibitors via an “adsorption–coating–hydrophobicity” mechanism, with a cuttings rolling recovery rate of 93.6% and a 16 h linear swelling rate of 1.0%. SLIP outperformed existing lubricants through a “microsphere rolling–adsorption film-forming” mechanism, with an extreme-pressure lubrication coefficient of 0.064 and an anti-wear load-bearing capacity of 10 kg. Laboratory evaluations showed that, after high-temperature aging at 150 ℃, the system maintained a yield point/plastic viscosity ratio of ≥0.5, an API filtration loss of <4 mL, a sand-bed pressure-bearing capacity of >7 MPa, strong contamination resistance, and a core permeability recovery value of >86.3%. Field applications in 12 extended-reach wells in several offshore blocks in China demonstrated that tripping friction was reduced by more than 30% and the rate of complex incidents decreased by 65%, providing a reliable technical option for the safe and efficient drilling of extended-reach wells.

Low-damage Water-based Drilling Fluid Technology for Fractured Tight Sandstone Reservoirs

Ma Zhe, Liu Junyi

2026, 43(4): 470-478. doi: 10.12358/j.issn.1001-5620.2026.04.005

Abstract(32) HTML (12) PDF (2525KB)(7)

Abstract:
The tight sandstone reservoirs in a certain block of the Shengli Oilfield are characterized by high density and well-developed fractures, which make them highly susceptible to drilling fluid damage during drilling. Through evaluations of reservoir mineral composition, porosity and permeability characteristics, and sensitivities, the primary causes of reservoir damage were analyzed. Accordingly, this study developed a new temporary plugging agent capable of self-degradation at reservoir temperatures and constructed a low-damage water-based drilling fluid system. The results indicated that the reservoir faced damage from solid phase plugging of fractures, water blocking, water sensitivity, and acid sensitivity. The developed epoxy resin-based self-degradable temporary plugging agent underwent network depolymerization via ester bond hydrolysis and transesterification reactions at high temperatures, generating soluble oligomers. At a reservoir temperature of 120 ℃, its degradation rate reached 21.8% after 48 h and 96.4% after 96 h. In addition, its compressive strength significantly exceeded that of calcium carbonate, a commonly used temporary plugging agent. Performance evaluation experiments on the low-damage drilling fluid demonstrated that it possessed excellent properties in rheology, filtration control, lubricity, and clay hydration inhibition. Simulated fracture plugging and core permeability recovery experiments showed that solid phases, including the temporary plugging agent, rapidly formed a sealing layer within the fractures during drilling. This sealing layer maintained good pressure-bearing capacity even after standing for 48 h at 120 ℃. After standing for 48–72 h, the structure of the sealing layer broke down, and following a 24 h flowback period, the core permeability recovery exceeded 90%, namely that formation damage was avoided effectively. Field tests in three wells demonstrated that this drilling fluid exhibited excellent lost circulation prevention and control effects. Furthermore, it effectively protected the reservoir through the self-degradation of the temporary plugging agent, resulting in a 91.83% increase in crude oil production in comparison with offset wells. can undergo network depolymerization through ester bond hydrolysis at high temperatures, generating soluble oligomers. At the reservoir temperature of 120 ℃, its degradation rate reaches 21.8% after 48 hours and 96.4% after 96 hours, with compressive strength far exceeding that of calcium carbonate, which is the typical temporary plugging agent. Performance evaluation experiments of the low-damage drilling fluid show that it exhibits excellent rheological properties, filtration control, lubrication, and clay hydration inhibition. Simulated fracture plugging experiments and core permeability restoration tests demonstrate that solid-phase materials such as the temporary plugging agent rapidly form a plugging layer in fractures during drilling. After static placement at 120 ℃ for 48 hours, the plugging layer still maintains good pressure-bearing capacity. After 48 to 72 hours of static placement, the structure of the plugging layer breaks down, and the core permeability recovery value exceeds 90% after 24 hours of flowback, effectively avoiding reservoir damage. Field tests conducted on three wells indicate that the drilling fluid demonstrates excellent performance in leak prevention and plugging. Additionally, the self-degradation of the temporary plugging agent effectively protects the reservoir, resulting in a 91.83% increase in crude oil production compared to offset wells.

Analysis on Wellbore Instability Mechanism of Jurassic Formation and Plugging Anti-collapse Drilling Fluid Technology

Fu Denghuang, Wan Mingqing, Luo Jingbing, Ke Jin, Zou Jun, Wang Bo

2026, 43(4): 479-488. doi: 10.12358/j.issn.1001-5620.2026.04.006

Abstract(32) HTML (14) PDF (3485KB)(7)

Abstract:
Well Qiantan-1 is a wildcat well located at the Niudong structure in the Qaidam Basin. To address the wellbore instability challenge in the Jurassic formation it encountered, a systematic study was conducted, including geological characteristic characterization, instability mechanism analysis, development of plugging and anti-sloughing drilling fluid, and its field application, by comprehensively adopting methods such as core observation, scanning electron microscopy (SEM), mineral analysis, mechanical testing, numerical simulation and field tests. The results show that the dominant mechanism of wellbore instability in this formation is the mechanical sliding of high-steep fractures combined with spalling of hard and brittle rocks, with insufficient thermal stability and poor plugging and inhibition performance of drilling fluid being the key engineering inducing factors. The developed temperature-resistant, plugging and inhibition synergistic drilling fluid system realizes the performance indicators of HTHP fluid loss ≤12 mL, filter cake thickness ≤2 mm and core rolling recovery rate ≥98% at a high temperature of 180 ℃ through optimizing temperature-resistant materials, compounding multi-level plugging agents and strengthening the inhibition system. Field application of this system has reduced the occurrence rate of wellbore collapse in the fifth spud by 80%, increased the rate of penetration (ROP) by 52%, and controlled the wellbore enlargement rate within 8%. The established instability criteria and prevention & control technology for hard and brittle formations with high-steep fractures provide a theoretical basis and engineering example for drilling in similar formations, and possess important on-site guiding value.

Characteristics and Measures or Prevention of Continuous Contamination by High-Temperature and High-Pressure CO₂

Li Wenzhe, Wang Rui, Wang Yao, Xia Lianbin, Wang Qiutong, Huang Tao

2026, 43(4): 489-497. doi: 10.12358/j.issn.1001-5620.2026.04.007

Abstract(29) HTML (8) PDF (3684KB)(7)

Abstract:
To address the persistent contamination of drilling fluids by CO₂, the CO₂ contamination to drilling fluids in the Penglai gas field in the Sichuan Basin is analyzed. In laboratory simulating experiment with high-temperature high-pressure (HTHP) CO₂ contamination, the characteristics of persistent HTHP CO₂ contamination was understood, and a set of measures for persistent CO₂ contamination prevention and treatment was developed. The experimental results show that when persistent CO₂ contamination is encountered, the concentrations of contaminant ions such as CO₃²⁻ and HCO₃⁻ in the drilling fluid increase, and the pH of the drilling fluid decreases. This is due to the neutralization of CO₂ by the caustic bases in the drilling fluid, instead of the dissolution and ionization of the CO₂ molecules in water. In the treatment of a water-based drilling fluid, continual application of caustic soda results in continuous increase in the concentrations of CO₃²⁻ and HCO₃⁻ in the drilling fluid. Bentonite platelets become fine particles under the action of CO₃²⁻/HCO₃⁻, and the fine particles tend to aggregate due to CO₃²⁻/HCO₃⁻-mediated dipole and hydrogen-bonding actions, thereby causing the drilling fluid to become viscosified. The synergy of a calcium additive and BK519 (a thinner) can be used to effectively prevent and deal with the persistent HTHP CO₂ contamination. The achievement made in this research provides a theoretical and technical support to the in-depth revealing and effective preventing of persistent CO₂ contamination encountered in deep formations.

Effects of Oil-Based Drilling Fluid Components on Performance of Stator Rubber in Positive Displacement Motors

Ouyang Jianglin, Zhang Ling, Yang Jianyu

2026, 43(4): 498-505. doi: 10.12358/j.issn.1001-5620.2026.04.008

Abstract(33) HTML (10) PDF (2267KB)(5)

Abstract:
Oil-based drilling fluids are commonly used in drilling deep and ultra-deep wells. However, in many drilling companies and many wells in northwest China, the service life of oil- and high-temperature-resistant positive-displacement-motors (PDM) used in oil-based drilling fluids varies erratically, in some cases, rubber detachment even occurs after only a dozen hours of operation. In laboratory experiment, two types of PDM stator rubbers with different crosslinking densities were soaked in different oil-based drilling fluids to test their rates of volume change and hardness change. The experiment was conducted at different temperatures with the stator rubbers and the oil-based drilling fluids collected from different drilling companies. The experimental results show that number 0 diesel oil exerts very slight effect on stator rubber, and the higher the crosslinking density, the stronger its resistance to medium-induced swelling. Oil-based drilling fluid components of the same commercial name but from different manufacturers differs to some extent in their effect on the hardness and rate of volume change of the PDM stator rubber. The main components of the oil-based drilling fluid from the drilling company X have minor effect on the stator rubber, while the secondary emulsifier and the wetting agent from the drilling company Y exert significant impact. After hot rolling at 180 ℃ for 48 hours in the emulsifier from the drilling company Y, the rubber B experienced a rate of volume change of 42.94% and Shore A hardness change of −17.2 HA. Meanwhile, after hot rolling under the same conditions in the wetting agent, the rubber B experienced a rate of volume change of 27.06% and Shore A hardness change of −9 HA. The aniline point and thermal weight loss of the main components of an oil-based drilling fluid cannot be used as technical parameters affecting the swelling of the stator rubber. The results of Fourier transform infrared spectroscopy (FT-IR) and gas chromatography-mass spectrometry (GC-MS) analyses demonstrate that the amide components in the secondary emulsifier and the wetting agent from the drilling company Y are the main factors causing volume change of the PDM stator rubber. After removing the amide components from the oil-based drilling fluid, the problem of rubber detachment from PDMs was effectively addressed.

CEMENTING FLUID

Design, Preparation and Property Study of Hydrocarbon-Triggered Self-Healing Materials

Tian Baozhen, Zhang Ye, Jia Chaoyang, Gao Fei, Ren Meng, Liu Tianle, Liu Xiaowen

2026, 43(4): 506-514. doi: 10.12358/j.issn.1001-5620.2026.04.009

Abstract(34) HTML (9) PDF (5158KB)(5)

Abstract:
In the long-time service life of a cement sheath, micro-annuli and microfractures are easy to be generated therein due to the formation stress variations and the complex chemical environment, resulting in sustained casing pressure and loss of interlayer isolation. The use of hydrocarbon-triggered self-healing materials is an effective means of addressing this problem. Under an environment with both cement slurry and methane, a comparison was made of the expansion ratios by hydrocarbon absorption of a self-developed hydrocarbon-triggered self-healing material DBC-CA, namely, borate-crosslinked cyclodextrin-acrylate compounded resin, and a hydrogenated styrene-butadiene block copolymer (SEBS). The expansion mechanisms and thermal stability of these two hydrocarbon-triggered self-healing materials were investigated through 3D computed tomography (CT), scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR) and thermogravimetric analysis (TGA). The results of the research show that the expansion performance of DBC-CA in different environments is superior to that of SEBS, and DBC-CA also shows good thermal stability. In a methane environment, the highest expansion rate of DBC-CA is 37%, and DBC-CA is quite responsive to the environment, with its maximum expansion ratio in a cement slurry being less than 8%. A cement slurry containing 10% DBC-CA shows the best performance in minimizing the widths of the microfractures and in eliminating connected seepage channels. Morphological analysis demonstrates that the elastic energy dissipation characteristics of DBC-CA results from a triple protection mechanism involving rigid framework, dynamic bond rearrangement and nanocavities. DBC-CA can slightly reduce the 28-day compressive strength of a set cement. The achievements of this research provide a new idea for the design of downhole self-healing sealing materials for deep gas well application.

Study and Application of Low Penetration Cement Slurry for Cementing CCUS Wells in Chuanyu Area

Xu Weiqiang, Liu Sen, Zhang Xiaobing, Wen Chunyu, Li Hailong, Deng Tianan

2026, 43(4): 515-521. doi: 10.12358/j.issn.1001-5620.2026.04.010

Abstract(43) HTML (14) PDF (3997KB)(8)

Abstract:
Well cementing in the Chuanyu area (Sichuan and Chongqing) is faced with corrosion, deterioration and failure of sealing of cement sheath in acidic condition. To address these issues, a corrosion-resistant material DST with both filming adsorption and microstructure regulation and control functions was developed, and with DST, a low-permeability corrosion-resistant cement slurry was formulated. Different from conventional corrosion-resistant materials, DST can induce corrosive hydration products to transform from a loose structure to a dense spherical calcium carbonate packing, thereby blocking the deep penetration of the corrosive media. Based on the typical bottomhole temperature and pressure conditions (80 ℃/40 MPa), laboratory acid corrosion experiment and field application were conducted. The results show that after being corroded for 28 days, the compressive strength of the set cement is only reduced by 5%. The permeability of the set cement, although slightly increased, is finally lower than 4 × 10⁻⁵ μm². The diameters of the main pores are kept at 10 – 90 nm, which are harmless or only slightly harmful, and no connected pores and loose structures are observed in the micromorphology of the set cement. This cement slurry has been applied in cementing a CCUS well in the Chuanyu area, and the first and the second bonding interfaces of the cement sheath are qualified at a rate exceeding 94%. In subsequent 300-day injection and production operations, no abnormal sustained pressure and CO₂ leaking were monitored. The key corrosion-resistant material DST developed in this research and the low-permeability corrosion-resistant cement slurry significantly improve the long-term sealing of the CCUS wellbore and lay a solid foundation for cementing CO₂ storage wells.

Preparation and Mechanism of HEDP-Intercalated Hydrotalcite Retarder

Liu Yan, Yang Zengmin, Ren Qiang, Liu Jingli, Cao Hongchang, Wang Jing, Yang Yuhang

2026, 43(4): 522-533. doi: 10.12358/j.issn.1001-5620.2026.04.011

Abstract(25) HTML (4) PDF (9575KB)(5)

Abstract:
To address the problem of slow strength development of the top cement with retarders at large temperature differences, a 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP) intercalated hydrotalcite Mg/Al-HEDP-LDH retarder was developed for use in large temperature difference environment. The retarder was prepared by intercalating HEDP in between the layers of hydrotalcite. Performance evaluation of the retarder in cement slurries shows that the optimal conditions for preparing Mg/Al-HEDP-LDH are as follows: pH = 4.5, crystallization temperature = 150 ℃, and crystallization time = 6 hours. The HEDP molecules between the layers of Mg/Al-HEDP-LDH is released during the hydration process of the cement particles to act as a retarder. At a concentration between 0.3% and 0.7%, Mg/Al-HEDP-LDH performs in a stable manner; with an increase of the concentration of Mg/Al-HEDP-LDH, the thickening time of the cement slurry increases. Mg/Al-HEDP-LDH increases the early strength of a cement slurry; at concentrations of 0.3%, 0.5% and 0.7%, the 1-day, 3-day, 7-day and 14-day strengths of the set cement are all higher than that of the blank cement slurry, especially the 1-day and the 3-day strengths, which increase significantly. The maximum 3-day strength is 92.9% – 103.6% higher than that of the blank cement slurry. The novel intercalated hydrotalcite Mg/Al-HEDP-LDH has retarding capacity in cement slurries, and can promote the development of the early strength of set cement.In summary, the novel intercalated hydrotalcite material Mg/Al-HEDP-LDH exhibits a retarding effect in cement slurry and can promote the development of the early strength of set cement.

Mud-Cake Displacement Agents for Moderate to Low Temperature Conditions

Tu Siqi, Sun Fuquan, Zou Shuang, Xie Feiyan, Sha Linhao, Zhao Hongjing, Shao Guanghui

2026, 43(4): 534-540. doi: 10.12358/j.issn.1001-5620.2026.04.012

Abstract(27) HTML (7) PDF (3552KB)(7)

Abstract:
During cementing operations in medium- and low-temperature oil and gas wells, mud cakes formed by water-based drilling fluids with strong viscosity, shear force, and high adsorption capacity exhibit dense structures and strong adhesion. Existing flushing agents generally suffer from insufficient penetration, low flushing efficiency, and poor adaptability to low temperatures, which easily lead to poor cementing quality at the second interface and engineering hazards such as annular channeling. To address these problems, based on the core principles of penetration, chelation, deflocculation, wetting, and wedge splitting, a multi-component synergistic system comprising FC-1, PA-2, diethylene glycol butyl ether, and phosphates was constructed through formulation optimization. Consequently, a novel flushing agent S-2 capable of rapidly removing mud cakes with high flushing efficiency under medium- and low-temperature conditions was developed. The comprehensive performance of S-2 was systematically characterized through laboratory evaluations and field tests. The results indicated the followings: (1) S-2 exhibited excellent compatibility and met the operational requirements for various types of water-based drilling fluids, including polymer, polysulfonate, and potassium-based drilling fluids. (2) Within the medium- and low-temperature range from room temperature to 80 °C, S-2 achieved a mud cake removal rate of over 90% within 5–10 min. Compared with commercially available flushing agents, it exhibited a flushing efficiency increased by more than 190%, demonstrating outstanding rapid stripping capability against mud cakes with strong viscosity, shear force, and high adsorption capacity. (3) S-2 had a low pour point of −18 °C and maintained good fluidity at −10 °C, meeting transportation and storage requirements in low-temperature environments. (4) S-2 showed excellent compatibility with both drilling fluids and cement slurries, effectively improving the cementing quality at the second interface. This flushing agent was successfully applied in the Φ244.5 mm production casing cementing operation of Well xxx in the Bohai Oilfield. The cementing quality was evaluated as excellent. It demonstrated a favorable application effect and provided new technical support for high-quality cementing in medium- and low-temperature oil and gas wells.

A High-strength Elastic-tough Cement Slurry System and Its Application in Coalbed Methane Horizontal Well Cementing

Hou Pan, Li Xin, Wen Lijuan, Tang Shouyu, Zhang Lianghong, Su Jingyi, Yao Zhiyin

2026, 43(4): 541-548. doi: 10.12358/j.issn.1001-5620.2026.04.013

Abstract(90) HTML (34) PDF (7065KB)(15)

Abstract:
Coalbed methane horizontal well cementing requires the cement stone to possess not only high strength but also good elasticity and toughness. A high-strength elastic-tough cement slurry system was developed by synthesizing a polymer microsphere material TRF with a core-shell structure, which was rigid outside and elastic inside, as an elastic-tough additive. The research results showed that this cement slurry system had a 75% increase in flexural strength, an 8.8% decrease in compressive strength, and a 38% reduction in elastic modulus after 48 h. It exhibited superior impact resistance performance to other toughening agent systems. After 14 days, the static compressive strength, dynamic strength, and absorption energy were increased by 96.12%, 115.16%, and 355.87%, respectively. The bonding performance was good, with a 29.4% increase in bonding strength at interface I and a 43.1% increase at interface Ⅱ. The anti-channeling performance was excellent. The pore pressure curve decreased smoothly without rebound, and the transition time of the static gel curve was short (only 5.5 min), representing an 82% reduction. This cement slurry system was successfully applied in Well BaiZ15-L1 in the Baicheng coalbed methane block, achieving excellent cementing quality in the horizontal well section, with bonding quality enhanced markedly at interfaces I and Ⅱ in comparison with offset wells. This high-strength elastic-tough cement slurry system met the requirements for coalbed methane horizontal well cementing.

FRACTUREING FLUID & ACIDIZING FLUID

Fracture Propagation Patterns of Pre-CO₂ Fracturing in Shale Oil Reservoirs

Tian Ganghua, Xia Qi, Wang Haizhu, Cheng Xu, Wang Bin

2026, 43(4): 549-561. doi: 10.12358/j.issn.1001-5620.2026.04.014

Abstract(51) HTML (15) PDF (10359KB)(6)

Abstract:
Using CO₂ as a fracturing fluid can enhance reservoir stimulation effect and achieve carbon sequestration. The CO₂ pre-pad fracturing technology combines the advantages of both CO₂ fracturing and water-based fracturing, serving as an important approach to improving fracturing performance in shale reservoirs. In this study, a thermal-hydro-mechanical-damage (THMD) coupled fracture propagation model was established for CO₂ pre-pad fracturing. Through numerical simulations, the evolution patterns of stress, temperature, fluid pressure, and damage during the CO₂ pre-pad fracturing process were analyzed, and the effects of CO₂ injection mode, injection volume, and injection rate on fracture propagation were investigated. The results indicated that fracture propagation was jointly driven by thermal stress and fluid pressure. The influence of thermal stress was primarily confined to a range of approximately 5 m near the wellbore, but its effect could not be ignored. The injection mode of injecting CO₂ first followed by slickwater proved more conducive to promoting fracture propagation. A non-monotonic relationship was observed between the CO₂ injection volume and the reservoir stimulation effect, and excessive CO₂ injection might inhibit damage evolution. When the CO₂ injection volume was 500 m³, the stimulation effect was optimal with a damage area of 629.91 m², which was 41.82 m² larger than that of conventional hydraulic fracturing. Furthermore, as the CO₂ injection rate increased, both the damage area and fracturing efficiency increased. These findings provided a theoretical basis for optimizing CO₂ pre-pad fracturing parameters in shale reservoirs and the efficient utilization and geological sequestration of CO₂.

Ultra-High Temperature CaCl₂ Weighted Fracturing Fluid Technology for Ultra-Deep High-Pressure Reservoir Stimulaiton

Wang Liwei, Gao Ying, Shi Yang, Yang Zhanwei, Peng Jianxin, Liu Ju

2026, 43(4): 562-568. doi: 10.12358/j.issn.1001-5620.2026.04.015

Abstract(18) HTML (6) PDF (3823KB)(3)

Abstract:
The continual breakthrough in exploring deep, ultra-deep and ultra-high pressure reservoirs has raised higher demands on heavy fracturing fluids. Fracturing fluid additives presently in use have various shortages, for example, KCl can raise the density of fracturing fluids to only a low density, bromides can raise the density of fracturing fluids to much higher densities, they are quite expensive though. Weighted guar gum fracturing fluids and weighted clear surfactant fracturing fluids, on the other hand, have poor high-temperature stability. To meet the requirements of stimulating reservoirs that are more than ten-thousand meters in depths, a technical study was conducted on ultra-high temperature weighted calcium chloride (CaCl₂) fracturing fluid. By selecting the salts for weighting, synthesizing polymers that are stable at high temperatures and high salinities, and developing delayed/controllable crosslinkers, all of which are key to the formulation of an ideal fracturing fluid, a cost-effective CaCl₂-weighted fracturing fluid which is resistant to ultra-high temperatures up to 220 ℃, was developed. The density of the fracturing fluid ranges from 1.15 g/cm³ to 1.35 g/cm³. The results of a comprehensive performance evaluation of the fracturing fluid show that after shearing for 2 hours at 180 – 220 ℃, the fracturing fluid, with varying compositions, has a viscosity that is greater than 50 mPa·s. The crosslinking time of the fracturing fluid is controllable. After standing for 2 hours at 180 ℃, no sand settling occurs. The rate of drag reducing of this fracturing fluid is greater than 50%. This fracturing fluid has been applied many times in the well Take-1, a well with bottomhole temperature of 205 ℃, the properties of the fracturing fluid were stable, and 308 m³ fracturing fluid was successfully used. The successful application of this weighted fracturing fluid technology provides a valuable experience for ultra-deep ultra-high pressure reservoir stimulation.

Preparation and Performance Evaluation of a High Performance Salt Resistant Emulsion Drag Reducer for Shale Oil Formation Fracturing

Li Jianshen, Huang Qiushi, Yan Songbing, Liu Qing, Wang Maogong, Dong Jingfeng, Zheng Miao

2026, 43(4): 569-576. doi: 10.12358/j.issn.1001-5620.2026.04.016

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Abstract:
Conventional fracturing fluids for shale fracturing are formulated with high-salinity flow-back waters, and the conventional polyacrylamide (PAM) emulsion drag reducer cannot meet the requirements of field operations because of its poor salt tolerance. To address this problem, a high-performance salt-resistant emulsion drag reducer was developed using hydrophobic functional monomer P-400, which has block structure, and copolymer monomers such as acrylamide (AM), acrylic acid (AA) and 2-acrylamido-2-methylpropanesulfonic acid (AMPS) through inverse emulsion polymerization. The solid content, oil/water ratio, concentrations of the monomer P-400 and the polymerization monomers AM and AMPS were optimized to obtain the desired product. The experimental results show that a salt-resistant emulsion drag reducer with the optimal performance can be obtained under these conditions: solid content = 35%, oil/water ratio = 3:7, P-400 concentration = 0.1%, AM concentration = 58.8% and AMPS concentration = 15%. A fresh water containing 0.05% (wt) of the synthesized drag reducer can reduce the friction of the water by 78%. 10% NaCl solution and standard brine treated with 0.05% (wt) of the drag reducer have their friction reduced by 72% and 70%, respectively. Molecular dynamics simulations confirmed at the microscopic scale the synergistic effect of introducing block functional monomers on the drag-reduction and salt-resistance performances, and the mechanism thereof. Moreover, rheological test results show that the drag reducer is a typical pseudo-plastic fluid, having excellent viscoelasticity and shear resistance. This high-performance salt-resistant emulsion drag reducer has the potential of application in shale oil and gas production.