钻井液与完井液

Abstract:
Oil-based drilling fluids in recent years have been widely used in drilling high-temperature deep wells, ultra-deep wells, strongly water-sensitive shales and salt-rock formations, as well as complexly-structured wells demanding high lubricity such as extended-reach horizontal wells, fishbone-type wells and multilateral wells. However, oil-based drilling fluids cause serious environmental pollution, and their application is also restricted by these factors such as high cost and the availability of core additives (such as emulsifiers). Using low oil/water ratio oil-based drilling fluids, the cost can be significantly reduced, the requirements for the performance of emulsifiers are stringent though. In recent years, research efforts both in China and abroad have been devoted to the development of high-performance emulsifiers and a series of low oil/water ratio oil-based drilling fluids have been developed. This paper reviews the emulsifier technology for low oil/water ratio oil-based drilling fluids and oil-based drilling fluids of different oil/water ratios both in China and abroad, and analyzes the research progress and existing challenges encountered in the development of low oil/water ratio oil-based drilling fluids to try to provide a guidance for the future research and development of this drilling fluid technology.

DRILLING FLUID

Establishment and Field Application of a Method for Evaluating Plugging Efficiency of a Drilling Fluid in Fractured Formations

Zhang Mingming, Li Daqi, Liu Jinhua, Li Tao, Zhang Dujie, Cui Kaixiao

2026, 43(5): 584-591. doi: 10.12358/j.issn.1001-5620.2026.05.002

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Abstract:
The Ordovician system and the Chuanxi marine carbonate formation in Shunbei oil and gas field are developed with broken formations, and borehole wall collapse have been frequently encountered during drilling. To stabilize the borehole wall with the density of the drilling fluid, it is necessary for the drilling fluid to perform well in plugging the fractured formations. Methods presently in use for evaluating the plugging capacity of a drilling fluid use porous filtration media which cannot represent the fracture development characteristics of fractured formations. To simulate the filtration behavior of a fluid in a fractured formation, a plugging capacity evaluation method was developed using slotted filter papers, thin metal sheets with acid-itched microfractures as well as 3D printed disks with fractures of various sizes, and using the thin metal-sheets with acid-itched microfractures method, the high temperature polymer sulfonate drilling fluid (mixed with oil) used on the well SHB83CH was evaluated for its microfracture plugging capacity and was then optimized. The results of the evaluation show that, for the acid-itched metal sheets method, metal sheets with 30 μm microfractures can be batch produced, and thus has the advantage of significantly higher test precision over the 3D printed disk method (the width of the fractures has deviation >50%). The number of the fractures is positively exponentially correlated with the total volume of filter loss, the width of a fracture has a quadratic function relationship with the volume of spurt filter loss, and the total volume of filter loss has a negative quadratic function relationship with the width of a fracture. An increase in the width of a fracture results in a more significant increase in the volume of the spurt filter loss, while the total volume of the filter loss tends to remain constant. The volume of the spurt filter loss can be used to evaluate the rate of mud cake formation and the effect of the mud cake on plugging the microfractures, and the total volume of filter loss can be used to evaluate the compactness of the mud cake. Field application showed that the use of the optimized drilling fluid reduced the percent hole enlargement to less than 5%. The evaluation methods established in this study provide a reliable technical means for screening plugging materials for fractured formations.

CFD-DEM-Based Study on Particle-Size Matching of Bridging Particles in Multi-Scale Fractures

Tian Xiaoqing, Xu Gege, Han Dong, Yang Lijie, Wang Lan, Xie Binqiang

2026, 43(5): 592-602. doi: 10.12358/j.issn.1001-5620.2026.05.003

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Abstract:
To address the limitation of traditional particle-size matching rules in lost circulation control for multi-scale fractured formations, coupled CFD-DEM simulations and laboratory simulated fracture-plugging evaluation experiments were performed on multi-scale wedge-shaped fractures. A dimensionless stability coefficient S was defined from the pressure-drop response. Gaussian process regression (GPR) was then used to establish the response relationship of S with fracture aperture and bridging particle-size ratio, forming a particle-size matching chart for multi-scale fractures. The results show that particle plugging-layer morphology and pressure-bearing response vary with fracture size. Suitable particle-size ratios allow bridging particles to form stable packing zones inside fractures and exhibit high pressure-bearing capacity, whereas smaller or larger ratios lead to deep migration, erosion-induced instability, or false plugging at the fracture inlet. The preferred particle-size ratio is 0.25-0.40 for 0.2-1 mm fractures and 0.35-0.45 for 1.5-2.5 mm fractures. The chart agrees with experimental data, with R²=0.8674, indicating good fitting accuracy within the research range.

Development and Performance of a Dual-phenyl-bridged Ultra-high Temperature Emulsifier for Oil-based Drilling Fluids

Wang Quande, Jiang Guancheng, Feng Qi, Feng Haiping, Han Chengfu, Zhang Yusong

2026, 43(5): 603-612. doi: 10.12358/j.issn.1001-5620.2026.05.004

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Abstract:
This study aimed to address the technical challenges of insufficient thermal stability and easy failure of the oil-water interfacial film in existing oil-based drilling fluid emulsifiers during ultra-high-temperature (>220 ℃) deep well and 10,000-meter-level ultra-deep well drilling. Based on the design concepts of rigid-skeleton-enhanced thermal stability andmulti-site adsorption,the study synthesized a novel ultra-high-temperature emulsifier (UHT-EM) featuring a double-benzene-bridged skeleton, double long-chain alkyl groups, and double calcium sulfonate head groups, using lauric acid and diphenylethane as raw materials. The molecular structure was characterized by infrared spectroscopy and proton nuclear magnetic resonance (1H NMR) spectroscopy. The emulsification performance and interfacial film strength were evaluated in terms of thermal stability, low-frequency oscillation, and microscopic morphology, and an ultra-high-temperature oil-based drilling fluid system based on UHT-EM was formulated. The results showed that the emulsion containing 1.0% UHT-EM exhibited ES of 1431 V after aging at 230 ℃ for 16 h, which remained at 729 V at 250 ℃, and dropped to 430 V at 260 ℃, significantly outperforming the emulsifiers HTM and Span80. Low-frequency oscillation tests indicated that the storage modulus G′ reached 649–801 Pa at low strain amplitudes and was consistently significantly higher than G″, demonstrating an elasticity-dominated high-strength characteristic. Microscopic morphology analysis showed that the emulsion maintained regular spherical shapes and a unimodal narrow particle size distribution within 230–250 ℃, whereas coalescence and destabilization occurred at 260 ℃ due to the synergistic failure of molecular anchoring and ionic crosslinking. The ultra-high-temperature oil-based drilling fluid formulated with UHT-EM (oil-water ratio 80∶20, density 2.0 g/cm³) achieved an ES value of 1226 V and FL_HTHP of 28.0 mL after aging at 230 ℃ for 16 h. By virtue of the molecular synergy between the double-benzene-bridged rigid skeleton and the double calcium sulfonate head groups, UHT-EM significantly improved the thermal decomposition temperature and interfacial film strength, exhibiting excellent emulsification stability at 250 ℃. It can provide core material support for oil-based drilling fluids used in 10,000-meter-level ultra-deep well and ultra-high-temperature deep well drilling.

Synthesis and Evaluation of a Sulfonated Biophenol-Modified Resin as a High-Temperature and Environmentally Friendly Filtrate Reducer

Liu Hao, Yang Xiaohua, Ren Rikun, Zhang Baichuan, Wang Haibo, Zhang Xin

2026, 43(5): 613-619. doi: 10.12358/j.issn.1001-5620.2026.05.005

Abstract(126) HTML (62) PDF (3898KB)(9)

Abstract:
With the ongoing expansion of oil and gas exploration into deep and ultra-deep wells, alongside escalating demands for green, low-carbon development and cost-effective efficiency, the development of drilling fluid additives that combine high-temperature resistance, low viscosity impact, environmental compatibility, and low cost has emerged as a critical direction for the industry. This study utilized lignin recovered from papermaking waste liquor as the primary raw material to successfully synthesize a high-temperature, environmentally friendly filtrate reducer—sulfonated biophenol-modified resin SMBMP-1—through alkali-oxygen degradation and graft modification processes. Experimental results demonstrate that the additive exhibits temperature resistance up to 180 ℃, salt tolerance to saturation, and calcium resistance of 3%. Its high-temperature, high-pressure fluid loss was only 14.6～15.4 mL, significantly outperforming the SMP-II industry standard (≤35 mL). Regarding environmental performance, it shows an EC₅₀ value of 259,000 mg/L and a BOD₅/COD_Cr ratio of 0.23, indicating it is non-toxic and readily biodegradable. Furthermore, the additive exhibits a low viscosity effect and demonstrates good compatibility within drilling fluid systems. The development of sulfonated biophenol-modified resin provides robust product support for rheological control and wellbore stability in deep and ultra-deep well drilling. It also holds significant importance for promoting the high-value utilization of biomass resources in the drilling fluid industry.

Laboratory Study on Phase Change Microcapsules DM@SiO₂ for Drilling Fluids

Wang Maoren, Liang Hongrui, Shi Yujie, Wu Yongbin

2026, 43(5): 620-630. doi: 10.12358/j.issn.1001-5620.2026.05.006

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Abstract:
To explore the potential of phase change microcapsules (PCMs) in temperature regulation within ultra-deep wellbores, this study successfully prepared PCMs DM@SiO₂ with D-mannitol (DM) as the core material and an inorganic shell layer of SiO₂ by the sol-gel method. The morphology, chemical structure, crystal form, heat storage performance, and thermal stability of DM@SiO₂ were systematically analyzed through scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD), and simultaneous thermal analysis (STA). Additionally, numerical simulations of wellbore heat transfer were conducted. The results indicated that the DM@SiO₂ particles were intact with a clear core-shell structure. The phase change latent heat reached 224.59 J/g, and the encapsulation efficiency was 76.76%. Performance evaluations showed that under a high-temperature condition of 180 ℃, at addition amounts of 10% and 15%, DM@SiO₂ maintained white oil at 167 ℃ for 6 min and 10 min, respectively, demonstrating a significant cooling delay effect. Meanwhile, it exhibited excellent thermal stability, shear resistance, alkali resistance, and compatibility with oil-based drilling fluids. Numerical simulation results revealed that DM@SiO₂ could form a 167 ℃ isothermal phase-change zone at well depths of 9000 m and 10 000 m. In the 9 000 m well, this isothermal zone extended to the bottom hole. For the 10 000 m well, the maximum length of the isothermal zone reached 2.869 km at DM@SiO₂ addition amount of 15%. DM@SiO₂ could also significantly reduce the fluid temperature in the high-temperature section. DM@SiO₂ holds promising application prospects for lowering wellbore temperatures during drilling fluid circulation.

An Amphoteric Copolymer Coated Carbon Nanotube Low Viscosity Filter Loss Reducer with High Cationicity

Wang Guoshuai, Sun Jun, Feng Yong, Zhou Chuxiang, Deng Zhengqiang

2026, 43(5): 631-639. doi: 10.12358/j.issn.1001-5620.2026.05.007

Abstract(108) HTML (31) PDF (3403KB)(12)

Abstract:
High density saturated saltwater drilling fluids at 220 ℃ have rheology, filtration rate and stability that are difficult to control. To address this issue, a low-viscosity fluid loss reducer CNT/ZPE was developed. CNT/ZPE uses carbon nanotube (CNT) as the rigid carrier, and is synthesized through the cation-π and π-π stacking interactions between nitrogen cations/aromatic rings and CNTs. In a CNT/ZPE molecule, the CNT is coated with high cationicity amphoteric copolymer ZPE. Using CNT/ZPE as the sole copolymer fluid loss reducer, a high density saturated saltwater drilling fluid that can be used at temperatures up to 220 ℃ was formulated with other conventional drilling fluid additives. The results of Fourier transform infrared spectroscopy and transmission electron microscopy analyses show that the CNT/ZPE molecules contain the designed quaternary ammonium cations, benzene rings and sulfonic acid groups etc., and the surfaces of CNTs are successfully coated with high cationicity amphoteric copolymer molecules. A salt-saturated base mud (containing 36% NaCl) and a calcium base mud (containing 2% CaCl₂) treated with 3% CNT/ZPE have API filtration rate of only 5.4 mL and 6.0 mL after aging at 220 ℃, respectively. The apparent viscosity (AV) of 1% CNT/ZPE water solution is only 5mPa·s, lower than the AVs of the water solutions of other regularly used low-viscosity copolymer fluid loss reducers, such as DSP-1, PSP and SO-1 at the same concentration. The formulated saturated saltwater drilling fluid, at densities between 2.0 g/cm³ and 2.3 g/cm³, have reasonable rheological parameters and controllable high-temperature high-pressure fluid loss after aging at 220 ℃ for 16 hours and 48 hours, respectively. It is resistant to the contamination of 0.7%CaCl₂, and is able to satisfy the requirements of field drilling operations. This study also provides a new strategy for developing CNT-based polymer compound materials for use in drilling fluids.

Parametric analysis of a coordinated temperature-control strategy for drilling fluid in ultra-deep wells

Wang Hao, Li Jingbin, Li Peisen, Wang Tianshu, Li Huan, Guo Chenrui

2026, 43(5): 640-648. doi: 10.12358/j.issn.1001-5620.2026.05.008

Abstract(114) HTML (39) PDF (7930KB)(10)

Abstract:
With the increasing depletion of shallow oil and gas resources, the exploration and development of deep and ultra-deep reservoirs have progressively become the primary focus. However, high bottomhole temperatures pose a critical challenge to the safe and efficient drilling of ultra-deep wells. This study proposes a coordinated temperature control method for drilling fluid, combining surface ice-particle cooling and downhole thermal insulation. Based on a case study of an 8,543 m ultra-deep well in the Tarim Basin, a transient wellbore heat transfer model was established to systematically analyze the influence of multiple factors on the circulating bottomhole temperature. An optimized wellbore temperature control strategy was subsequently proposed. The results demonstrate that insulating the drill pipe effectively reduces the bottomhole temperature, with performance improving as the thermal conductivity of the coating decreases. Among the operating parameters, drilling fluid flow rate has the most significant impact—bottomhole temperature decreases as the flow rate increases. Regarding thermophysical properties, heat capacity and density exhibit a stronger influence on bottomhole temperature, whereas thermal conductivity and viscosity play relatively minor roles, primarily affecting the convective heat transfer process by altering the Nusselt number. Furthermore, thermal insulation significantly enhances the cooling effect of other parameters, particularly the inlet temperature. Without insulation, reducing the inlet temperature from 80 ℃ to 0 ℃ only affects the shallow section, leaving the bottomhole temperature nearly unchanged. In contrast, with insulation, the same inlet temperature drop reduces the bottomhole temperature by approximately 28 ℃. Therefore, effective temperature control in ultra-deep wells requires the synergistic application of multiple technical measures. This study provides theoretical guidance for managing the wellbore temperature field during deep drilling operations.

Rock-fluid Interaction Mechanisms in Deep Coal Rock-parting Formations and Drilling Fluid Countermeasures in the Daji Block

Wang Wei, Jin Jiafeng, Qi Zongkai, Miao Qiang, Wang Zenglong, Yang Gan, Xu Jie

2026, 43(5): 649-660. doi: 10.12358/j.issn.1001-5620.2026.05.009

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Abstract:
To address wellbore instability in deep coalbed methane horizontal wells in the Daji Block on the eastern margin of the Ordos Basin, systematic analyses were conducted of the core mineral composition, macro- and microstructural characteristics, physicochemical properties, and mechanical properties. The rock-fluid interaction mechanisms in the deep coal rock-parting formations in this block were subsequently identified. The results show that the hydration-induced weakening of the primary cleat-fracture system in the coal rock acts synergistically with hydration-induced microfracture dilation, secondary-fracture development, and clay mineral hydration and swelling in the dark-gray argillaceous partings. The resulting deterioration in the mechanical strength of the coal rock-parting composite formation is the dominant factor controlling wellbore instability in the horizontal sections of coalbed methane wells. Based on the identified rock-fluid interaction mechanisms, a synergistic wellbore-stability strategy integrating “multistage plugging, hydrophobic inhibition, density matching, and precise control” is proposed. A drilling fluid system with strong plugging, inhibition, and supporting capabilities is developed using film-forming and hydrophobic functional additives as the core treatment agents. Laboratory performance evaluations show that all performance parameters meet the engineering requirements. Field application demonstrated that this drilling fluid system enabled the successful completion of Well JS6-3P02. The well had a 2062 m horizontal section, achieved 100% penetration of the coal-seam target interval, and required only 7 d to drill the horizontal section. The horizontal section was drilled to total depth in a single bit run without any downhole complications. It was the first deep coalbed methane horizontal well with a horizontal section exceeding 2,000 m to be completed in the Daji Block. The developed drilling fluid system meets the requirements for drilling coalbed methane wells with long horizontal sections and has good potential for wider application.

Key Drilling and Completion Technologies and Application of the First Parametric Well in Dailekh, Nepal

Wang Jingpeng, Li Jun, Lian Wei, Yang Jixiang, Wang Zhiguo, Zheng Tao, Zhang Xuejia

2026, 43(5): 661-669. doi: 10.12358/j.issn.1001-5620.2026.05.010

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Abstract:
The parametric well Nidaican-1 is the first parametric well drilled in Dailekh, Nepal. Through comprehensive application of geological well logging technology, the identification of the formation lithology, the evaluation of the formation pressure while drilling, the description of reservoir physical properties, and the interpretation and evaluation of the oil/gas/water zones, have been completed, identifying the oil and gas exploration potential of this area. To tackle the difficulties in drilling the high-silica metamorphic quartz sandstones with high hardness and abrasiveness, the assembly of “MWD + single-bend PDM + turbodrill” was adopted to optimize well-path control. Coupled with the strategy of reinforcing the bit materials and bit structure, the rate of penetration was increased by at least 50%, and the footage drilled by a single bit exceeded 300 m. Using the novel potassium calcium based polymer drilling fluid, wellbore instability encountered in drilling the thrust nappe zone was successfully solved, with a rate of hole enlargement of only 6.1%. Using well cementing technology combined contamination-/lost circulation-preventive cement slurry and rigid-elastic centralizer combinations, the casing string was successfully set at a depth of 4,011 m. The integrated geological evaluation-drilling engineering technology established includes (1) drilling assembly and parameter optimization method for drilling in thrust nappe zones aimed at “preventing deviated drilling and drilling fast”; (2) strongly inhibited drilling fluid composition with high plugging capacity; and (3) standard practice for well cementing in complex structural zones. The achievements made not only fill the technical gap in deep hydrocarbon drilling in Nepal, but also bear important practical significance for promoting energy cooperation around the Himalayas.

CEMENTING FLUID

Experimental Study on Secondary-hydration Self-healing Performance of Microcracks in Wellbore Cement Sheaths

Liu Huajie, Zhang Yudi, Zhu Rui, Syed, Zhang Huanan, Li Shaopeng, Sergey Chernyshov

2026, 43(5): 670-679. doi: 10.12358/j.issn.1001-5620.2026.05.011

Abstract(81) HTML (35) PDF (2174KB)(6)

Abstract:
The sealing integrity of cement sheaths in well cementing is directly related to the operational safety and service life of oil and gas wells. However, complex service conditions can readily induce microcracks, which, if not repaired at an early stage, may lead to corrosive fluid invasion, casing deterioration, and other risks. Existing studies have paid insufficient attention to short-term repair performance and rheological properties. In this paper, Class G high-sulfate-resistant oil well cement was used as the base material, and six latent reactive materials were selected as secondary-hydration self-healing agents. Through single-additive screening and the construction of composite systems, the short-term self-healing effects after 3 and 7 days of curing were investigated in terms of rheological properties, compressive strength, and permeability. The results show that among the single-additive systems, 10% silica fume and 1% sodium silicate exhibit the best repair performance, with strength recovery rates reaching 70.6% and 78.5%, respectively, after 7 d of curing. The composite systems exhibit a significant synergistic effect. Among them, the system containing 20% fly ash and 1% sodium silicate exhibits the best overall performance, with a strength recovery rate of 72.37% and a permeability reduction rate of 60.69% after 7 d of curing, while also offering lower cost and good field applicability. The developed self-healing agent overcomes the limitations of traditional materials, such as slow reaction and high cost, and provides technical support for early-stage wellbore repair in oil and gas wells. It is of great engineering significance for ensuring wellbore integrity, reducing costs, and improving efficiency.

Formulation and Evaluation of High-Temperature Large Temperature-Difference Low-Density Cement Slurry

Yang Lyuchao, Meng Renzhou, Zhang Xiaolin, Zhai Xianzhi, Zhang Chi, Ye Sutao

2026, 43(5): 680-687. doi: 10.12358/j.issn.1001-5620.2026.05.012

Abstract(66) HTML (29) PDF (4285KB)(7)

Abstract:
Deep and ultra-deep wells generally have ultra-deep and long cementing hole sections, and some of them also have low-pressured and thief zones that make the operation difficult. In cementing these wells, the cement slurries are faced with technical challenges such as high bottomhole temperature, large temperature-difference, and slow strength development of low-density set cement etc., making it difficult to balance the regulation of thickening time, the stability of cement slurry and the strength of set cement. Using a self-developed high-temperature suspension stabilizer and a thickening time regulator for large temperature-difference, a low-density cement slurry for working under high temperature and large temperature-difference was formulated based on close-packing theory to optimize the sizing of the particles. The density of the cement slurry can be adjusted between 1.20 g/cm³ and 1.55 g/cm³. Experimental results show that the hydrophobic association effect of the high-temperature suspension stabilizer slows down the reduction of the solution viscosity between 70 ℃ and 160 ℃. The large-temperature-difference thickening time regulator, by releasing temperature-sensitive functional groups, achieves “weak retarding at the top and strong retarding at the bottom”. The cement slurry formulated, after aging at a high temperature of 200 ℃, have 0 free water and sedimentation stability of less than 0.05 g/cm³. Under large temperature-differences, the low-temperature section of the top set cement has a 48-hour strength of 3.6 MPa, which can meet the requirements of supporting the casing strings and ensuring drilling ahead. At 120 ℃ – 180 ℃, the 14-day strength of the set cement exceeds 13 MPa, with no obvious strength degradation occurred in 28 days. This high-temperature low-density cement slurry for large temperature-difference conditions provides a technical idea for addressing the problems of high-temperature instability, thickening time regulation and low strength of low-density cement slurries. It also provides support to safe and high-quality cementing of low-pressure deep- and ultra-deep- wells with thief zones.

A Pre-Flush for Lost Circulation Control Based on Expandable Fiber-Grafted Resin

Ma Chunxu, Sun Chao, Zou Yiwei, Zhi Caifu, Dong Xiliang, Wang Chengwen

2026, 43(5): 688-694. doi: 10.12358/j.issn.1001-5620.2026.05.013

Abstract(51) HTML (24) PDF (3226KB)(6)

Abstract:
With the exploration of oil and gas into deep and complex formations, lost circulation in fractured formations has become a complicated problem affecting the quality of well cementing. The pre-flushes for lost circulation control presently in use exhibit poor adaptability to fractured and high-temperature formations, making it difficult to ensure well cementing safety and return height of cement slurry. To solve this problem, a novel pre-flush for lost circulation control system was presented based on expandable fiber-grafted resin bridged with compounded rigid calcite and sepiolite fibers. Using Fourier transform infrared spectroscopy, the structure of the fiber-grafted resin was characterized, and the rheology, plugging capacity, compatibility and acid solubility were evaluated. The results show that the pre-flush can seal fractures of 1 – 4 mm in width, and has pressure bearing capacity exceeding 5.0 MPa, demonstrating that the pre-flush has favorable adaptive filling characteristics and improves significantly the plugging effect in fractured formations. The pre-flush exhibits stable rheology, the high-pressure filtration rate of which is less than 30 mL, and it prevents solid particles from invading fractures. The pre-flush is well compatible with cement slurries, and it basically shows no adverse effect on the development of the compressive strength of a cement slurry. For fractured reservoirs, the pre-flush can be removed in late stage with low concentration hydrochloric acid, a hydrochloric acid of 5% dissolve 92.97% of the plugging zone. This pre-flush for lost circulation control can significantly reduce the risk of lost circulation and mitigate damage to fractured reservoirs, providing a new technical approach for lost circulation control in cementing wells penetrating fractured formations.

High-Thixotropy Lost Circulation Control Cement Slurry Technology for the Rumaila Oilfield in Iraq

Zhai Xiangyu

2026, 43(5): 695-701. doi: 10.12358/j.issn.1001-5620.2026.05.014

Abstract(69) HTML (27) PDF (3390KB)(7)

Abstract:
To address the severe lost circulation in fracture- and vug-developed formations of the Rumaila Oilfield in Iraq, where conventional lost circulation control cement slurries are difficult to form effective plugs, a fully dry-blended low-density, low-strength thixotropic cement slurry system with a density of 1.30 g/cm³ was developed based on thixotropic mechanism analysis. This was achieved through the selection of thixotropic agents, optimization of lightweight materials, and regulation of early strength performance. Thixotropy evaluation methods were established using the static shear stress difference method and the consistency increment method to study the effects of a biopolymer thixotropic agent on the rheological and thixotropic properties of the cement slurry. The results show that with 0.1% biopolymer BDJ as the thixotropic agent, the low-density cement slurry system exhibits excellent thixotropic performance: a 30 min consistency increment of 39 Bc and a 30 min gel strength of 170 Pa. The setting time of the thixotropic cement slurry system is shortened to 5.0 h, and the 24 h compressive strength reaches 5.3 MPa, achieving the dual goals of “saving plugging time and preventing the drilling of new boreholes.” Compared with similar domestic and international technologies, this system demonstrates significant advantages in density, thixotropy, and early strength. Field test validation shows that the non-productive time for plugging operations is reduced by more than 30% compared to wells in the same block of the Rumaila Oilfield, providing a new technical solution for lost circulation control in low-pressure and easily lost-circulation formations.

FRACTUREING FLUID & ACIDIZING FLUID

Synthesis and Performance Evaluation of a High-Temperature Resistant Long-Acting Self-Generated Acid Fluid System

Li Mingxuan, Yao Yiming, Chen Chen, Li Daqi, Wu Xiongjun

2026, 43(5): 702-710. doi: 10.12358/j.issn.1001-5620.2026.05.015

Abstract(55) HTML (25) PDF (2402KB)(4)

Abstract:
In response to the challenges in acidizing deep high-temperature carbonate reservoirs, where conventional acids react too rapidly and existing self-generated acids suffer from insufficient acid-generated capacity and poor temperature resistance, this study developed a novel high-temperature resistant acid-generated agent, SFACA, and constructed a high-temperature long-lasting self-generated acid system based on it. Experimental results demonstrate that SFACA operates via an efficient "activation-hydrolysis-dissociation-cyclic catalysis" acid generation mechanism, capable of continuously releasing hydrogen ions within the temperature range of 60～180 ℃. Its acid generation activity is effectively activated above 140 ℃, achieving an effective hydrogen ion concentration of up to 7.8 mol·kg⁻¹. Furthermore, the acid concentration can be flexibly regulated by optimizing the agent-to-water mass ratio. The self-generated acid system constructed based on SFACA exhibits good compatibility and demonstrates efficient dissolution capability toward the primary mineral of carbonate rocks, CaCO₃. The effective acid-rock reaction durations at 160 ℃ and 180 ℃ are 7 h and 4 h, respectively, with corresponding acid-rock reaction rates of 1.45×10⁻⁷ mol·cm⁻²·s⁻¹ and 2.46×10⁻⁷ mol·cm⁻²·s⁻¹, highlighting its long-lasting performance characteristics. Additionally, the system exhibits good corrosion inhibition, with dynamic corrosion rates on N80 steel coupons measured at 56.3 g·m⁻²·h⁻¹ and 67.8 g·m⁻²·h⁻¹ at 160 ℃ and 180 ℃, respectively. The high-temperature long-lasting self-generated acid system achieves high acidity, sustained release, and efficient etching under high-temperature conditions, providing reliable technical support for the efficient stimulation of deep high-temperature carbonate reservoirs at 160～180 ℃ range.

COMPLETION FLUID

Development and Mechanism of a Bio-Based Water-Blocking Prevention Workover Fluid for Offshore Oilfields

Li Zhizhen, Yang Kai, Shi Bin, Su Yanhui, Geng Xueli, Zheng Xiaobin

2026, 43(5): 711-718. doi: 10.12358/j.issn.1001-5620.2026.05.016

Abstract(58) HTML (29) PDF (3846KB)(8)

Abstract:
In response to the severe water-blocking damage easily induced by invasive foreign fluids during workover operations in offshore low-to-medium permeability oilfields, this study developed a bio-based workover fluid system for water-blocking prevention based on modified rhamnolipids. The system involves the cationic modification of rhamnolipids with glycidyltrimethylammonium chloride (GTMAC) to synthesize a water-blocking prevention agent with low interfacial tension and wettability control capabilities. This agent addresses the issue of precipitation caused by traditional rhamnolipids in the presence of divalent cations such as calcium and magnesium. By combining it with anti-swelling agents and chelating agents, a complete workover fluid system was formulated. Through experiments including aqueous phase contact angle measurement, interfacial tension analysis, core flooding, low-field nuclear magnetic resonance (NMR), X-ray photoelectron spectroscopy (XPS), and atomic force microscopy (AFM), the performance of the system was systematically evaluated, and its mechanism of action was elucidated. The results indicate that this workover fluid can increase the aqueous phase contact angle on core surfaces to 104.7°, achieving a reversal of wettability to hydrophobic/neutral. The oil-water interfacial tension can be reduced to the order of 10⁻² mN/m. Core flooding experiments demonstrated a permeability recovery rate of 109.79%, significantly higher than that of the blank sample (56.74%). Mechanistic analysis reveals that the cationically modified rhamnolipids strongly electrostatically adsorb onto rock surfaces via quaternary ammonium groups, with their hydrophobic tails self-assembling to form a low-surface-energy molecular film. Synergized with ultra-low interfacial tension, this effectively reduces capillary resistance, promotes the discharge of trapped aqueous phases, thereby preventing and mitigating water-blocking damage, and demonstrates promising application potential.