钻井液与完井液

Abstract:
Wellbore working fluids are critical enabling technologies for the safe and efficient exploration and development of unconventional, deep, and ultra-deep oil and gas resources. This paper reviews and benchmarks domestic and international advances in wellbore fluid technologies. The results show that comparable performance has been achieved in high-performance water-based drilling fluids for unconventional reservoirs and in wellbore fluids for deep and ultra-deep applications, while notable gaps remain in reservoir protection technologies and intelligent control systems. With the continuous deepening of exploration and development, existing wellbore working fluids are still insufficient to meet the increasing demands of deeper, longer, and smarter drilling operations. Therefore, further efforts are required to promote iterative upgrading toward environmentally friendly, high-performance, and intelligent wellbore fluid systems, and to develop fully autonomous formulations integrated with advanced testing and control technologies.

DRILLING FLUID

A Model for Predicting Borehole Wall Stability in High Stress Fractured Formations

WANG Weiji, ZHANG Dujie

2026, 43(2): 152-160. doi: 10.12358/j.issn.1001-5620.2026.02.002

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Abstract:
To deal with the wellbore collapse and instability problems encountered in drilling the broken marine carbonate formations in Shunbei and western Sichuan, a visual true triaxial wellbore instability physical simulation experimental platform was prepared and used to study the microstructural characteristics, physiochemical characteristics and mechanical properties of the broken formations, and it was understood that concentrated geostress, formation fragmentation and the mechanical-chemical coupling effect between the drilling fluid and the rocks are the main controlling factors for wellbore instability. By introducing a formation integrity coefficient, a parameter relationship between the “formation integrity coefficient + drilling fluid soaking” and formation mechanics was established. Based on finite element simulation, the distribution of the geostress of the broken formations was revealed. Based on equivalent rock mechanics parameters and taking into account the chemical interaction between drilling fluid and rock, a collapse pressure prediction model based on M-C criterion was constructed. The prediction accuracy of collapse pressure in typical wells, such as the well SHB9X, PZ5-3D and PZ6-5D, is as high as 86.0%-93.9%.

A New High-temperature Tackifier for Solid-free Drilling Fluids

ZHOU Guowei, ZHANG Xin, YAN Weijun, HUA Guiyou, ZHANG Zhenhua, QIU Zhengsong

2026, 43(2): 161-171. doi: 10.12358/j.issn.1001-5620.2026.02.003

Abstract(1149) HTML (896) PDF (4086KB)(49)

Abstract:
The Ordovician buried-hill reservoir in Liaohe Oilfield exhibits a challenging high-temperature (200 ℃ at reservoir center) and low-pressure (pressure coefficient 1.01～1.06) environment characteristic of typical high-temperature, low-pressure oil/gas reservoirs. To achieve formation protection, a solids-free water based drilling fluid was prioritized, with tackifier selection being critical. Through molecular structure optimization, a novel high-temperature/salt-resistant tackifier was developed using four monomers: N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), N,N-diethylacrylamide (DEAA), and 1-(3-sulfopropyl)-2-vinylpyridinium hydroxide inner salt. The synthesis employed N,N'-methylene bisacrylamide as crosslinker with potassium persulfate and sodium bisulfite as redox initiators. FTIR and TGA analysis confirmed successful polymerization, demonstrating superior thermal stability with 296.66 ℃ initial decomposition temperature and only 45.96% mass loss during degradation phase, outperforming commercial HE300. The fluid achieved remarkable rheological performance with 722 consistency coefficient (K) at 0.5% concentration. Laboratory evaluations verified exceptional thermal stability up to 220 ℃ and saturated salt tolerance. Field applications demonstrated excellent viscosity-enhancing performance and robust durability of this novel tackifier, providing vital technical support for buried-hill reservoir development and high-temperature formation drilling operations.

Research and Application of Elastic Expanding Bridging Efficiency-Enhancing Material

CUI Kaixiao, LIU Jinhua, LI Daqi

2026, 43(2): 172-178. doi: 10.12358/j.issn.1001-5620.2026.02.004

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Abstract:
Current bridging lost circulation materials (LCMs) exhibit poor lost circulation control performance and limited pressure bearing capacity when used in controlling mud losses into complex fractured formations such as those with multiscale fractures and stress-sensitive fractures, and mud losses controlled with these LCMs are easy to re-occur. Based on the idea of enhancing the elasticity and toughness as well as the volumetric expandability of the LCMs, an elastic expanding bridging efficiency-enhancing material was developed. The optimal synthesis formula and conditions were obtained through component optimization experiments. Laboratory evaluations were conducted on the material mechanics, expansion performance and lost circulation control capacity of the elastic expanding bridging efficiency-enhancing material, followed by field application. The research findings show that the elastic expanding bridging efficiency-enhancing material exhibits high compressive strength and good elasticity-toughness before and after expansion. After aging at 160 ℃, the volume of the elastic expanding bridging efficiency-enhancing material can expand to 116.67% of its original volume. Through elastic-tough deformation and continuous three-dimensional expansion, the elastic expanding bridging efficiency-enhancing material can enhance the compactness of the plugging layers and improve their elasticity-toughness, thereby strengthening the pressure-bearing and anti-breathing capacity of the seal. Preliminary field applications of this elastic expanding bridging efficiency-enhancing material in wells with lost circulation in the southwest drilling block have achieved favorable results in mud loss control, demonstrating broad promotion prospects.

Drilling Fluid Technology for Ultra-High Temperature Fractured Bedrock Reservoirs

HAO Shaojun, XING Xing, AN Xiaoxu, WEI Shijun, ZOU Jun, HAO Tian

2026, 43(2): 179-187. doi: 10.12358/j.issn.1001-5620.2026.02.005

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Abstract:
The Kunteyi gas field is located in the #1 buried structure of the Kunteyi sag on the northern margin of the Qaidam Basin, the bedrock reservoirs of which are developed with fractures and have a weathering crust, and the formations of which have weak segments and natural channels for mud losses, together with complex geological conditions such as ultra-high temperatures (approximately 200 ℃) and abnormal high pressures (pressure coefficient up to 1.63). To address the drilling fluid challenges confronted in drilling ultra-high temperature bedrock reservoir formations, such as thick and loose mud cakes, low pressure-bearing capacity and ease of lost circulation etc., an ultra-high temperature drilling fluid with high plugging capacity for the prevention of lost circulation was developed through synergistic design of core additives. In the drilling fluid “SC-200+Redu240” are used to construct a high-temperature colloidally stable framework, and “nano-silica + white asphalt NFA-25” used to achieve plugging of the multiscale fractures and finally an integrated function of “filtration control + fracture plugging + wellbore stability” is realized. Experimental results confirm that this drilling fluid functions normally at temperatures up to 200 ℃. After aging, the rates of change in the apparent viscosity and plastic viscosity are both less than 3%, the high-temperature high-pressure filtration rate is less than 12 mL, and the drilling fluid can resist contamination by 15%NaCl. Additionally, the sand-bed filtration rate of the drilling fluid after aging is only 4.2 mL, and the filtration rate for fracture plugging is 8.6 mL, indicating that the drilling fluid has excellent fracture plugging capacity and formation pressure-bearing capacity. This drilling fluid exhibits remarkable effects in lost circulation control and wellbore stabilization in drilling ultra-high temperature fractured formations. In field application of this drilling fluid in the well K2-3 (well depth 7170 m, and bottomhole temperature 199.5 ℃), “zero mud loss” was achieved in drilling the bedrock section, and no downhole complex situation caused by lost circulation or drilling fluid properties occurred throughout the whole drilling process, with a complex time efficiency of zero. The application of this drilling fluid technology significantly reduced the non-productive time due to lost circulation, providing reliable technical support for the safe and efficient drilling of ultra-deep wells in this area.

Research on Class Structural Environmentally Friendly Emulsifiers for Oil-based Drilling Fluids

CHENG Bingfang, WANG Chengjun, BU Fankang, BAO Linghan, WANG Chongchong, XIANG Peng

2026, 43(2): 188-193. doi: 10.12358/j.issn.1001-5620.2026.02.006

Abstract(475) HTML (355) PDF (3288KB)(36)

Abstract:
Using environmentally friendly ester derivatives such as epoxy fatty acid esters as raw materials, react with polyamines to form a main emulsifier with a Gemini surfactant structure. Then, using the main emulsifier as raw material, partially sulfonate it to form a multi class environmentally friendly emulsifier with a similar structure for oil-based drilling fluids. The molecular structure of the emulsifier was determined through infrared and mass spectrometry characterization, with a temperature resistance of up to 180 ℃, a demulsification voltage of over 900 V, and an emulsification rate of over 90%. Capable of adapting to low oil-water ratio oil-based drilling fluid environments and drilling fluid systems formulated with different base oils. Adapt to drilling fluid systems with different densities. Has excellent biodegradability. A method for evaluating the microstructure of emulsion droplets was established to determine the stability of emulsion droplet formation, and it was determined that high emulsifier dosage can effectively improve the uniformity and high-temperature stability of oil in water emulsion droplets.

Development and Performance of a Water-Based Drilling Fluid Suspending Agent Resistant to 230 ℃

LIN Xin, LI Gongrang, YU Weichu

2026, 43(2): 194-201. doi: 10.12358/j.issn.1001-5620.2026.02.007

Abstract(30) HTML (8) PDF (3797KB)(7)

Abstract:
In high-temperature and ultra-high-temperature drilling operations, the decrease in drilling fluid gel strengths causes the settling stability and the sand carrying capacity of the drilling fluid to reduce, which results in uneven dispersion of the solid particles and cuttings agglomeration in the drilling fluid. To address this problem, a quaternary polymer drilling fluid suspending agent, XFJ-3^#, which exhibits temperature resistance up to 230 ℃, was designed and synthesized using AMPS (2-acrylamido-2-methylpropanesulfonic acid), SAS (sodium allylsulfonate), SSS (sodium p-styrenesulfonate) and MBA (methylene bisacrylamide) as the main raw materials. Fourier transform infrared spectroscopy (FT-IR), thermogravimetric analysis (TGA) and 1H nuclear magnetic resonance spectroscopy (¹H-NMR) were used to characterize XFJ-3^#. The results show that XFJ-3^# is the target product. XFJ-3^# loses only 60% of its weight at 600 ℃. Performance evaluation results show that a 5% Bohai drilling clay slurry treated with 1%XFJ-3^# retains more than 70% of its gel strengths after aging at 230 ℃ for 10 days. The suspending agent XFJ-3^# can effectively improve the ability of a drilling fluid to maintain its settling stability for a long time under ultra-high temperature environments.

Evaluation of Sulfide Removing Rate by Basic Zinc Carbonate in Oil Based Drilling Fluids and Analyses of Sulfide Removing Mechanisms

ZHANG Zhen, YIN Da, QIN Guochuan, CHEN Lin, WANG Gui

2026, 43(2): 202-208. doi: 10.12358/j.issn.1001-5620.2026.02.008

Abstract(23) HTML (9) PDF (2325KB)(4)

Abstract:
Basic zinc carbonate is a commonly used sulfide scavenger for drilling high-sulfide content formations with water-based drilling fluids, its ability to remove sulfide and the mechanism of sulfide removal in oil-based drilling fluids are still not well understood. In evaluating the rate if hydrogen sulfide removal, conventional methods use relatively low concentration and flow rate of hydrogen sulfide, the results of these methods are not suitable for high temperature application, and the reaction time in these methods is too short. To overcome these deficiencies of the old evaluation methods, a new experimental platform for evaluating the rate of sulfide scavenging of deep-well drilling fluids has been constructed. Using this platform, the rates of sulfide scavenging of basic zinc carbonate in oil, water, water-in-oil emulsion and oil-based drilling fluid were tested; the test results were used to analyze the existence forms of hydrogen sulfide in water-in-oil emulsions, the sulfide scavenging mechanisms of basic zinc carbonate in neutral and weakly-alkaline aqueous phases were clarified, and the sulfide scavenging mechanism of basic zinc carbonate in oil-based drilling fluids was then revealed. The test results show that the rate of sulfide scavenging of basic zinc carbonate in oil-based drilling fluids can be as high as 100%; most of the hydrogen sulfide (>90%) invading into an oil-based drilling fluid exists as undissociated hydrogen sulfide molecules in the oil phase of the oil-based drilling fluid, and only a small fraction (<10%) of the invading hydrogen sulfide dissolves into the aqueous phase to form ions dominated by HS⁻. In the aqueous phase of an oil-based drilling fluid, the Zn²⁺ ions ionized from basic zinc carbonate react directly with the primary ionization product HS⁻ of hydrogen sulfide to form ZnS precipitate, and a high pH of the aqueous phase is not a necessary condition for sulfide scavenging; the reaction-diffusion coupling effect is the primary mechanism of sulfide scavenging by basic zinc carbonate in oil-based drilling fluids, and temperature increase is helpful to enhance the rate of sulfide scavenging. The revealed working mechanism of basic zinc carbonate in oil-based drilling fluids provides a scientific basis for using this chemical as a sulfide scavenger in oil-based drilling fluids.

CEMENTING FLUID

The Influence of Calcium-Based Whisker Self-Healing Agent on Self-Healing of Oil Well Set Cement Cracks in CCUS Wells

CAO Hongchang, DANG Donghong, ZHANG Ye, REN Qiang, LIU Jingli, LIU Yan, PENG Song, MA Jun

2026, 43(2): 209-216. doi: 10.12358/j.issn.1001-5620.2026.02.009

Abstract(31) HTML (10) PDF (4570KB)(2)

Abstract:
In wells for carbon capture, utilization and storage (CCUS), cement sheaths are easy to get chemically damaged, hence reducing their service life. A study was conducted to enhance the self-healing capacity of cement sheaths by reacting calcium-based whisker self-healing agent with CO₂ to produce CaCO₃. The influence of calcium-based whisker self-healing agent on the self-healing process of cement sheaths was studied using mechanical tester, X-ray diffractometer (XRD), thermogravimetric analyzer (TGA), scanning electron microscope (SEM) and industrial computed tomography (CT) etc. The results of mechanical performance tests showed that after 28 days of self-healing, the self-healing rate of the compressive strength of the set cement incorporated with the calcium-based whisker reached 83.87%, which is 90.31% higher than that of the set cement without incorporating calcium-based whisker. Phase analysis and SEM observation results show that a large number of calcite-type calcium carbonate crystals were generated around the self-healing material and deposited in the cracks of the set cement, thereby rendering the cracks in the set cement carbonized self-healing. CT test results further confirmed the self-healing effect of the calcium-based whisker self-healing agent; after 28 days of self-healing, the volume of the cracks in the set cement incorporated with the calcium-based whisker self-healing agent was reduced by 4,165.95 mm³, a self-healing rate of 72.32%. This indicates that in the CCUS well environment, the incorporation of calcium-based whisker self-healing materials into a cement slurry has a positive impact on the carbonized self-healing process of the cement sheath.

Preparation of C-S-H/APC Nanoseed and Its Effect on the Early Strength of Set Cement

FU Xiongtao, DONG Zhiming, LI Jiajia, ZHOU Xingchun, MA Haiyun

2026, 43(2): 217-222. doi: 10.12358/j.issn.1001-5620.2026.02.010

Abstract(33) HTML (15) PDF (4419KB)(3)

Abstract:
Hydrated calcium silicate/polycarboxylic acid nanocrystalline species (C-S-H/PCE) is a kind of nanocomposites with nucleation effect can accelerate the hydration reaction of cement and improve the early strength of cement stone, but the conventional anionic polycarboxylic acid dispersant has strong retarding effect. In this paper, a strongly dispersing and weakly retarding amphoteric polycarboxylic acid dispersant (APC) was firstly synthesized by introducing methacryloyloxyethyltrimethylammonium chloride cationic monomer, and then a hydrated calcium silicate/amphoteric polycarboxylic acid nanocrystalline seed (C-S-H/APC) with high early-strength performance was prepared from the APC, and the structure of the crystal seed was characterized. The compressive strength of C-S-H/APC cementite was 10.8%, 8.2% and 8.9% higher than that of C-S-H/PCE cementite when the addition amount of the crystalline seed was 1%, and the curing time at 20 ℃ was 6 h, 12 h and 24 h. The XRD patterns of C-S-H/APC cementite showed that the Ca(OH)₂ diffraction peaks were obviously stronger than that of the blank group, while those of C₂S and C₃S were lower than that of the blank group, and there were some water-induced and water-soluble peaks in the XRD patterns of the cementite. C₂S, C₃S, and the diffraction peaks of hydration product AFt were lower than those of the blank group. The SEM image of cement stone shows that the hydration degree of the blank cement stone is very low and the structure is loose, and the structure of the nanometer C-S-H/APC cement stone with the same age of maintenance is denser and the hydration degree of the cement is higher, which indicates that the nanometer C-S-H/APC improves the hydration rate of the cement and accelerates the formation of the spatial network structure of the hydration products, so as to improve the early strength of the cement stone, and the performance of this low-temperature early-strengthening agent slurry system is stable, and it has been used in Changqing Oil Industry. The low-temperature early strength cement slurry performs well and has been successfully applied in the low-temperature wells in the long 6 layers of Ordos Basin of Changqing Oilfield.

Cementing Slurry Technology for Ultra-deep and High-pressure Gas Storage

JI Xiangui, YU Gang, WANG Haitao, DING Hui, LI Kunpeng, XIONG Yudan, TENG Zhaojian

2026, 43(2): 223-233. doi: 10.12358/j.issn.1001-5620.2026.02.011

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Abstract:
With the drilling of gas storage wells in the Tarim basin towards ultra-deep high-pressure formations, well cementing engineering is confronted with multiple challenges, including deeper well drilling, high bottomhole temperature, low displacement efficiency, high risk of gas channeling, and easy failure of cement sheath under alternating loads. Conventional cement slurries can hardly satisfy the requirements of well cementing under such conditions. To deal with these challenges, a high strength tough self-healing cement slurry system suitable for cementing ultra-deep high-pressure gas-storage wells was developed with three core materials optimally selected through a large number of experiments, which are toughening agent BCE-X, self-healing agent BCY-Y and low viscosity filter loss reducer BCF-Z. In the development of the cement slurry system, the mechanisms of improving the strength of a tough cement slurry were investigated from close-packing theory, water/cement ratio control and displacement efficiency optimization, with the cement displacement process also optimized. The results of the research show that the high strength tough self-healing cement slurry system has a density range of 1.86-1.92 g/cm³, an adjustable thickening time, an API filter loss ≤ 50 mL, a settlement density difference of 0, a free water of 0, a 7-d elastic modulus ＜ 6.0 GPa, and a 7-d compressive strength at90 ℃＞30 MPa. This technology has been successfully applied in cementing the liner of the third-interval in the gas-storage well YC-H11 in the block Yaha in the Tarim oilfield. The percent qualified cementing job of the whole well is 99.7%, the rate of excellent job quality reaches 85.9%, and the continuous high-quality cement sheath in the cap rock section is longer than 25 m. It is concluded that through the synergistic effect of mechanical performance optimization and displacement efficiency enhancement, this technology significantly improves the long-term sealing integrity of ultra-deep high-pressure gas storage wells, providing reliable technical support for efficient construction of similar gas storage wells.

Research and Application of a Thermal-Resistant Fluid Loss Additive

LING Yong, WANG Qike, XIAO Yao, DU Bin, XU Yixin, LIU Wenming, SHANG Xiaoyang

2026, 43(2): 234-241. doi: 10.12358/j.issn.1001-5620.2026.02.012

Abstract(14) HTML (3) PDF (1998KB)(0)

Abstract:
Liquid AMPS-based fluid loss additives, when stored at medium-temperatures (50– 70 ℃), cause the thickening time of a cement slurry to prolong, thereby affecting the thickening stability of the cement slurry. To solve this problem, a series of filter loss reducers were designed and synthesized via free radical copolymerization using AMPS, amide-based monomers and unsaturated acid monomers. Among the final synthesized products, the ternary copolymer fluid loss additive P4, which was synthesized using monomers including AMPS, N,N-dimethyl acrylamide (DMAA) and acrylic acid (AA), was selected as the optimal final product. The effects of residue monomers, types of amide monomers, unsaturated acids and hydrolysis inhibitors on the properties of the final product were investigated and the retarding effect of the fluid loss additive was tested via medium-temperature thermal aging experiments. The experimental results show that at elevated ambient temperatures, a high content of residue monomers tends to cause the fluid loss additive to locally polymerize, the introduction of DMAA significantly inhibit the medium-temperature hydrolysis of the amide groups, and the fluid loss additive synthesized with monobasic small-molecule unsaturated carboxylic acid exhibits stable thickening performance. The hydrolysis inhibitor can inhibit the hydrolysis of the fluid loss additive in the early stage of thermal aging, but fails after long-term of thermal aging. After aging at 60 ℃ for 10 days, 30 days, 90 days and 12 months, the liquid ternary polymer fluid loss additive P4 maintains stable performance, with its comprehensive performance satisfying the requirements of the SY/T 5504.2-2013 standard. This study provides an effective solution to the storage of additives under high ambient temperatures.

Mechanism of Contact Contamination between Shale Inhibitors and Well Cement Slurries and Solutions Thereto

DENG Fei, ZHANG Ye, JIANG Peng, LIU Jingli, YANG Yuhang, CHENG Xiaowei, MEI Kaiyuan

2026, 43(2): 242-249. doi: 10.12358/j.issn.1001-5620.2026.02.013

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Abstract:
To solve the contact contamination between a cement slurry and a drilling fluid, drilling fluid additives that impose serious contamination to the cement slurry are selected and studied to understand their mechanisms of contamination and to find ways of preventing the contamination. As one of the commonly used drilling fluid additives, shale inhibitor DFZ-7 has significant effects on the rheology of the cement slurry. The effects of DFZ-7 on the performance of the cement slurry and its contamination mechanism were investigated by means of fluidity test, compressive strength test, XRD, IR, TG and SEM etc., and as a result of the investigation, an effective anticontamination strategy was developed. Experimental results show that at the early stage of cement hydration, the active groups in the DFZ-7 molecules can complex with the metallic cations on the surfaces of the cement particles to form network structures which hinder the movement of free water, causing the fluidity of the cement slurry to decrease and the viscosity thereof to increase. An anticontamination agent named KW was prepared by mixing aminotrimethylenephosphonic acid (ATMP) and titanium dioxide (TiO₂) in a mass ratio of 5∶1. KW can be used to solve the contamination of DFZ-7 to the cement slurry through chelation and interstitial action. By adding 5% KW in the cement slurry, the fluidity of the cement slurry returned from 17.6 cm to 23.8 cm, and the strength of the set cement aging at 90 ℃ for 1 d was increased from 1.56 MPa to 8.74 MPa. A mixture of the cement slurry and a drilling fluid (cement slurry∶drilling fluid = 7∶3) had a thickening time of 55 min under the test conditions of 205 ℃ × 125 MPa × 110 min. After treatment with KW (cement slurry∶drilling fluid∶spacer = 7∶2∶1), the thickening time of the mixture was increased to 353 min, satisfying the needs of operation. In the set cement, the number of the network structures generated by DFZ-7 complexation decreased and the content of hydration products increased. The incorporation of KW can solve the contact contamination to the cement slurry by DFZ-7, without changing the composition of the hydration products of the cement slurry.

FRACTUREING FLUID & ACIDIZING FLUID

Flow Characteristics of Dual-Increasing Stimulation Slurry in Unconsolidated Silty Sandstone

LIU Xilong, SUN Qian, ZHANG Guobiao, LI Bing, ZHANG Kewei

2026, 43(2): 250-261. doi: 10.12358/j.issn.1001-5620.2026.02.014

Abstract(1204) HTML (937) PDF (8359KB)(41)

Abstract:
The dual-increasing stimulation slurry is a novel stimulation fluid developed for weakly cemented reservoirs, such as submarine methane-hydrate-bearing silty sandstones. After injection into the formation, it consolidates to form porous-media slurry veins that enhance permeability. This study employed a slurry fracture flow visualization apparatus to investigate the flow characteristics of the slurry within muddy silty sediments. The experiments revealed the influence of geological parameters, slurry formulation, and operational parameters on slurry flow, fluid loss, and slurry-vein porosity. The results indicate that the slurry flows uniformly and exhibits a convex fracture flow profile, flowing to the end of main fracture and branch fracture, effectively filling fractures. Lower fluid loss increases the proportion of medium-to-large pores within the slurry veins. Adjusting the slurry formulation can reduce fluid loss in formations of varying permeability, whereas a high injection rate expands the fluid loss zone. The effective porosity ranges from 50% to 60% with a uniformly distributed pore space, forming a structure dominated by large pores (pore diameter > 50 nm) and densely distributed micro- to mesopores (pore diameter < 50 nm). This pore network can serve as high-conductivity channels for gas and water migration, while the dense distribution of small and medium pores is conducive to sand control.

Study on Interface Effect of Surfactant/Coal Composite System and Desorption Law of Methane

YUAN Pu, MU Songtao, WEI Zhenji, LI Chunhu, ZHU Xueguang, JIANG Zhao, MA Liang

2026, 43(2): 262-271. doi: 10.12358/j.issn.1001-5620.2026.02.015

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Abstract:
To address the key issue of surfactant-controlled coal wettability and desorption of methane in deep coalbed methane (CBM) development, coal-rock samples were taken from the Benxi Formation of the Erdos Basin to study the pattern of how surfactants, including cationic surfactant (TC-2), anionic surfactant (OBS), nonionic surfactant (OP-10) and zwitterionic surfactant (CHSB), affect the wettability of the coal rocks and the desorption process of methane. It was found in laboratory experiments, including surface tension measurement, contact angle measurement, Zeta potential characterization, imbibition experiment and micromorphology analysis, that the composite surfactant system OBS/CHSB, with their synergistic effect between the ionic surfactant and the zwitterionic surfactant, reduces the surface tension of the solution to 20.95 mN/m, and decreases the initial contact angle of the coal-rocks to 30.764°. This synergistic effect comes from the strong electronegativity of the sulfonic acid groups, which induces the expansion of the double electric layer, forcing the surfactant molecules to have their hydrophilic groups oriented outward. Meanwhile, the betaine groups of the surfactant CHSB reduce the micelle sizes through the charge shielding effect, enhancing the penetration capacity of the solution through the organic matter-clay mineral interface and further inducing the development of secondary solution pores. Fourier transform infrared spectroscopy (FT-IR) analysis further indicated that OBS treatment, through competitive adsorption, significantly increases the content of the carboxylic group (-COOH) on the coal surfaces to 18.88%, while TC-2, through π-π conjugation effect, increases its adsorption capacity on the coal surfaces. Methane desorption experimental results showed that at 0.5% OBS/CHSB composite surfactant treatment, the desorption capacity of methane reaches 7.37 mL/g, a percent increase of 78.5% over the raw coal. The mechanism of this effect can be attributed to the synergistic effect between wettability optimization and pore connectivity enhancement: the former weakens the confinement of capillary force on methane, while the latter forms multi-stage diffusion channels, hence achieving the synchronous improvement of diffusion-seepage dual-mode mass transfer efficiency. In field application, wells fractured with 0.3% desorption accelerator treatment in the fracturing fluids can produce gas in 5 days, with a stable gas production rate maintained at 6.6×10⁴ m³/d. The study confirmed that the composite surfactant system overcomes the contradiction between wettability regulation and pore plugging via the synergistic mechanism of “charge matching-pore reconstruction-mass transfer enhancement,” providing a theoretical basis for the efficient development of deep CBM resources.

Study and Application of the Mechanism of Reducing Sandstone Reservoir Damage by HPG with Repair Agent

XU Bingwei

2026, 43(2): 272-279. doi: 10.12358/j.issn.1001-5620.2026.02.016

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Abstract:
In sandstone reservoir hydraulic fracturing operation, the adsorption and retention of hydroxypropyl guar gum (HPG) on the surfaces of reservoir rocks cause significant formation damage which requires an urgent solution. It is decided, based on laboratory study, that a repair agent should be used to mitigate the formation damage by HPG and hence to improve the effect of sandstone reservoir fracturing. Using spectroscopy technology, the quantity of HPG adsorbed and retained in sandstones can be quantitatively studied, and using NMR technology, the effect of the repair agent on reducing formation damage by HPG can be characterized. Based on these studies, the optimum quantity of the repair agent to be used was determined, and the effects of temperature and retention period on the performance of the repair agent were investigated. Using X-ray photoelectron spectroscopy, SEM and contact angle measurement, the mechanisms of the repair agent to mitigate formation damage by HPG were revealed. The results of the study show that the optimum concentration of the repair agent is 3000 mg/L, and the formation permeability damage is reduced by 29.31%. Temperature has a relatively low effect on the performance of the repair agent. The effect of the repair agent on reducing formation damage first decreases and then increases with the time of HPG retention on the surfaces of the sandstones. Through hydrogen-bond inhibition, preferentially occupying adsorption sites and increasing interface contact angles, the repair agent mitigates the retention of HPG in sandstone reservoirs. The field application of the repair agent in Hangjinqi block showed that the concentrations of the guar gum in the waste fracturing fluids from wells treated with the repair agent were significantly increased, and the oil production was significantly increased and stabilized for a longer time. The results of the study provide technical support to the efficient development of sandstone reservoirs.

COMPLETION FLUID

Development and Plugging Mechanism of High Strength Epoxy Resin-Based Plugging Agent Used in Offshore Oil and Gas Wells with Sustained Annular Pressure

SU Yanhui, LI Zhizhen, HU Binglei, ZHANG Yunfei, GUI Peng, JIANG Yuxing, GENG Xueli

2026, 43(2): 280-288. doi: 10.12358/j.issn.1001-5620.2026.02.017

Abstract(10) HTML (2) PDF (3084KB)(1)

Abstract:
The problem of annular pressure buildup is especially prominent in offshore high temperature and high pressure oil and gas wells, which is prone to causing leakage, corrosion and failure of wellbore structure, thereby seriously endangering operational safety and wellbore integrity. To address the limitations of conventional cement and resin type plugging materials in flowability, curing controllability and mechanical properties, a novel high-strength epoxy-based plugging agent for operation under non-drilling string conditions was developed. This plugging agent is formulated by blending 35%-55% epoxy resin, 5% hyperbranched resin, 20%-30% diluent and 10%-40% medium-temperature curing agent. This plugging agent was evaluated in laboratory experiments on its rheology, mechanical properties, thermal stability and sealing performance. The experimental results show that this plugging agent has a good rheology at temperatures between 25 ℃ and 65 ℃ (with viscosity ranging from 35 to 185 mPa·s), a curing time that can be controlled between 0.11 h and 25 h, a compressive strength ranging from 31 to 63 MPa, and a bonding strength greater than 11 MPa/8 cm at temperatures between 20 ℃ and 100 ℃. It possesses excellent thermal stability (with decomposition temperature up to 380 ℃), and achieves zero permeability under 20 MPa gas pressure. With high strength, high temperature resistance and excellent sealing capacity, this plugging agent can be used in complex offshore environment and can provide technical support for annular pressure control in offshore wells.